Well task scheduling

ABSTRACT

A method can include receiving scheduled tasks associated with subsystems of a wellsite system wherein the scheduled tasks are associated with achievement of desired states of the wellsite system; transmitting task information for at least a portion of the scheduled tasks to computing devices associated with the subsystems; receiving state information via the wellsite system; assessing the state information with respect to one or more of the desired states; based at least in part on the assessing, scheduling a task; and transmitting task information for the task to one or more of the computing devices associated with the subsystems.

RELATED APPLICATIONS

This application claims priority to and the benefit of a U.S.Provisional Application having Ser. No. 62/149,619, filed 19 Apr. 2015,which is incorporated by reference herein.

BACKGROUND

A bore can be drilled into a geologic environment where the bore may beutilized to form a well. A rig may be a system of components that can beoperated to form a bore in a geologic environment, to transportequipment into and out of a bore in a geologic environment, etc. As anexample, a rig may include a system that can be used to drill a bore andto acquire information about a geologic environment, drilling, etc. Asan example, a rig can include one or more of the following componentsand/or equipment: a mud tank, a mud pump, a derrick or a mast,drawworks, a rotary table or a top drive, a drillstring, powergeneration equipment and auxiliary equipment. As an example, an offshorerig may include one or more of such components, which may be on a vesselor a drilling platform.

SUMMARY

A method can include receiving scheduled tasks associated withsubsystems of a wellsite system where the scheduled tasks are associatedwith achievement of desired states of the wellsite system; transmittingtask information for at least a portion of the scheduled tasks tocomputing devices associated with the subsystems; receiving stateinformation via the wellsite system; assessing the state informationwith respect to one or more of the desired states; based at least inpart on the assessing, scheduling a task; and transmitting taskinformation for the task to one or more of the computing devicesassociated with the subsystems. A system can include one or moreprocessors; memory operatively coupled to the one or more processors;and processor-executable instructions stored in the memory andexecutable by at least one of the processors to instruct the system toreceive scheduled tasks associated with subsystems of a wellsite systemwhere the scheduled tasks are associated with achievement of desiredstates of the wellsite system; transmit task information for at least aportion of the scheduled tasks to computing devices associated with thesubsystems; receive state information via the wellsite system; assessthe state information with respect to one or more of the desired statesto provide one or more assessments; based at least in part on at leastone of the one or more assessments, schedule a task; and transmit taskinformation for the task to one or more of the computing devicesassociated with the subsystems. One or more computer-readable storagemedia can include computer-executable instructions executable toinstruct a computing system to: receive scheduled tasks associated withsubsystems of a wellsite system where the scheduled tasks are associatedwith achievement of desired states of the wellsite system; transmit taskinformation for at least a portion of the scheduled tasks to computingdevices associated with the subsystems; receive state information viathe wellsite system; assess the state information with respect to one ormore of the desired states to provide one or more assessments; based atleast in part on at least one of the one or more assessments, schedule atask; and transmit task information for the task to one or more of thecomputing devices associated with the subsystems. Various otherapparatuses, systems, methods, etc., are also disclosed.

This summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

BRIEF DESCRIPTION OF THE DRAWINGS

Features and advantages of the described implementations can be morereadily understood by reference to the following description taken inconjunction with the accompanying drawings.

FIG. 1 illustrates examples of equipment in a geologic environment;

FIG. 2 illustrates an example of a system and examples of types ofholes;

FIG. 3 illustrates an example of a system;

FIG. 4 illustrates an example of a system;

FIG. 5 illustrates an example of a system;

FIG. 6 illustrates an example of a system and an example of a scenario;

FIG. 7 illustrates an example of a wellsite system;

FIG. 8 illustrates an example of a system;

FIG. 9 illustrates an example of a system;

FIG. 10 illustrates an example of a method;

FIG. 11 illustrates an example of a graphical user interface;

FIG. 12 illustrates an example of a graphical user interface;

FIG. 13 illustrates an example of a graphical user interface;

FIG. 14 illustrates an example of a graphical user interface;

FIG. 15 illustrates an example of a graphical user interface;

FIG. 16 illustrates an example of a method;

FIG. 17 illustrates an example of a method;

FIG. 18 illustrates an example of a method;

FIG. 19 illustrates examples of computing and networking equipment; and

FIG. 20 illustrates example components of a system and a networkedsystem.

DETAILED DESCRIPTION

The following description includes embodiments of the best modepresently contemplated for practicing the described implementations.This description is not to be taken in a limiting sense, but rather ismade merely for the purpose of describing the general principles of theimplementations. The scope of the described implementations should beascertained with reference to the issued claims.

Well planning is a process by which a path of a well can be mapped, soas to reach a reservoir, for example, to produce fluids therefrom. As anexample, constraints can be imposed on a design of a well, for example,a well trajectory may be constrained via one or more physical phenomenathat may impact viability of a bore, ease of drilling, etc. Thus, forexample, one or more constraints may be imposed based at least in parton known geology of a subterranean domain or, for example, presence ofother wells in the area (e.g., collision avoidance). As an example, oneor more other constraints may be imposed, for example, consider one ormore constraints germane to capabilities of tools being used and/or oneor more constraints related to drilling time and risk tolerance.

As an example, a well plan can be generated based at least in part onimposed constraints and known information. As an example, a well planmay be provided to a well owner, approved, and then implemented by adrilling service provider (e.g., a directional driller or “DD”).

As an example, a well design system can account for one or morecapabilities of a drilling system or drilling systems that may beutilized at a wellsite. As an example, a drilling engineer may be calledupon to take such capabilities into account, for example, as one or moreof various designs and specifications are created.

As an example, a well design system, which may be a well planningsystem, may take into account automation. For example, where a wellsiteincludes wellsite equipment that can be automated, for example, via alocal and/or a remote automation command, a well plan may be generatedin digital form that can be utilized in a well drilling system where atleast some amount of automation is possible and desired. For example, adigital well plan can be accessible by a well drilling system whereinformation in the digital well plan can be utilized via one or moreautomation mechanisms of the well drilling system to automate one ormore operations at a wellsite.

FIG. 1 shows an example of a geologic environment 120. In FIG. 1, thegeologic environment 120 may be a sedimentary basin that includes layers(e.g., stratification) that include a reservoir 121 and that may be, forexample, intersected by a fault 123 (e.g., or faults). As an example,the geologic environment 120 may be outfitted with any of a variety ofsensors, detectors, actuators, etc. For example, equipment 122 mayinclude communication circuitry to receive and/or to transmitinformation with respect to one or more networks 125. Such informationmay include information associated with downhole equipment 124, whichmay be equipment to acquire information, to assist with resourcerecovery, etc. Other equipment 126 may be located remote from a wellsite and include sensing, detecting, emitting or other circuitry. Suchequipment may include storage and communication circuitry to store andto communicate data, instructions, etc. As an example, one or morepieces of equipment may provide for measurement, collection,communication, storage, analysis, etc. of data (e.g., for one or moreproduced resources, etc.). As an example, one or more satellites may beprovided for purposes of communications, data acquisition, geolocation,etc. For example, FIG. 1 shows a satellite in communication with thenetwork 125 that may be configured for communications, noting that thesatellite may additionally or alternatively include circuitry forimagery (e.g., spatial, spectral, temporal, radiometric, etc.).

FIG. 1 also shows the geologic environment 120 as optionally includingequipment 127 and 128 associated with a well that includes asubstantially horizontal portion that may intersect with one or morefractures 129. For example, consider a well in a shale formation thatmay include natural fractures, artificial fractures (e.g., hydraulicfractures) or a combination of natural and artificial fractures. As anexample, a well may be drilled for a reservoir that is laterallyextensive. In such an example, lateral variations in properties,stresses, etc. may exist where an assessment of such variations mayassist with planning, operations, etc. to develop the reservoir (e.g.,via fracturing, injecting, extracting, etc.). As an example, theequipment 127 and/or 128 may include components, a system, systems, etc.for fracturing, seismic sensing, analysis of seismic data, assessment ofone or more fractures, injection, production, etc. As an example, theequipment 127 and/or 128 may provide for measurement, collection,communication, storage, analysis, etc. of data such as, for example,production data (e.g., for one or more produced resources). As anexample, one or more satellites may be provided for purposes ofcommunications, data acquisition, etc.

FIG. 1 also shows an example of equipment 170 and an example ofequipment 180. Such equipment, which may be systems of components, maybe suitable for use in the geologic environment 120. While the equipment170 and 180 are illustrated as land-based, various components may besuitable for use in an offshore system. As shown in FIG. 1, theequipment 180 can be mobile as carried by a vehicle; noting that theequipment 170 can be assembled, disassembled, transported andre-assembled, etc.

The equipment 170 includes a platform 171, a derrick 172, a crown block173, a line 174, a traveling block assembly 175, drawworks 176 and alanding 177 (e.g., a monkeyboard). As an example, the line 174 may becontrolled at least in part via the drawworks 176 such that thetraveling block assembly 175 travels in a vertical direction withrespect to the platform 171. For example, by drawing the line 174 in,the drawworks 176 may cause the line 174 to run through the crown block173 and lift the traveling block assembly 175 skyward away from theplatform 171; whereas, by allowing the line 174 out, the drawworks 176may cause the line 174 to run through the crown block 173 and lower thetraveling block assembly 175 toward the platform 171. Where thetraveling block assembly 175 carries pipe (e.g., casing, etc.), trackingof movement of the traveling block 175 may provide an indication as tohow much pipe has been deployed.

A derrick can be a structure used to support a crown block and atraveling block operatively coupled to the crown block at least in partvia line. A derrick may be pyramidal in shape and offer a suitablestrength-to-weight ratio. A derrick may be movable as a unit or in apiece by piece manner (e.g., to be assembled and disassembled).

As an example, drawworks may include a spool, brakes, a power source andassorted auxiliary devices. Drawworks may controllably reel out and reelin line. Line may be reeled over a crown block and coupled to atraveling block to gain mechanical advantage in a “block and tackle” or“pulley” fashion. Reeling out and in of line can cause a traveling block(e.g., and whatever may be hanging underneath it), to be lowered into orraised out of a bore. Reeling out of line may be powered by gravity andreeling in by a motor, an engine, etc. (e.g., an electric motor, adiesel engine, etc.).

As an example, a crown block can include a set of pulleys (e.g.,sheaves) that can be located at or near a top of a derrick or a mast,over which line is threaded. A traveling block can include a set ofsheaves that can be moved up and down in a derrick or a mast via linethreaded in the set of sheaves of the traveling block and in the set ofsheaves of a crown block. A crown block, a traveling block and a linecan form a pulley system of a derrick or a mast, which may enablehandling of heavy loads (e.g., drillstring, pipe, casing, liners, etc.)to be lifted out of or lowered into a bore. As an example, line may beabout a centimeter to about five centimeters in diameter as, forexample, steel cable. Through use of a set of sheaves, such line maycarry loads heavier than the line could support as a single strand.

As an example, a derrick person may be a rig crew member that works on aplatform attached to a derrick or a mast. A derrick can include alanding on which a derrick person may stand. As an example, such alanding may be about 10 meters or more above a rig floor. In anoperation referred to as trip out of the hole (TOH), a derrick personmay wear a safety harness that enables leaning out from the work landing(e.g., monkeyboard) to reach pipe in located at or near the center of aderrick or a mast and to throw a line around the pipe and pull it backinto its storage location (e.g., fingerboards), for example, until it atime at which it may be desirable to run the pipe back into the bore. Asan example, a rig may include automated pipe-handling equipment suchthat the derrick person controls the machinery rather than physicallyhandling the pipe.

As an example, a trip may refer to the act of pulling equipment from abore and/or placing equipment in a bore. As an example, equipment mayinclude a drillstring that can be pulled out of the hole and/or place orreplaced in the hole. As an example, a pipe trip may be performed wherea drill bit has dulled or has otherwise ceased to drill efficiently andis to be replaced.

FIG. 2 shows an example of a wellsite system 200 (e.g., at a wellsitethat may be onshore or offshore). As shown, the wellsite system 200 caninclude a mud tank 201 for holding mud and other material (e.g., wheremud can be a drilling fluid), a suction line 203 that serves as an inletto a mud pump 204 for pumping mud from the mud tank 201 such that mudflows to a vibrating hose 206, a drawworks 207 for winching drill lineor drill lines 212, a standpipe 208 that receives mud from the vibratinghose 206, a kelly hose 209 that receives mud from the standpipe 208, agooseneck or goosenecks 210, a traveling block 211, a crown block 213for carrying the traveling block 211 via the drill line or drill lines212 (see, e.g., the crown block 173 of FIG. 1), a derrick 214 (see,e.g., the derrick 172 of FIG. 1), a kelly 218 or a top drive 240, akelly drive bushing 219, a rotary table 220, a drill floor 221, a bellnipple 222, one or more blowout preventors (BOPs) 223, a drillstring225, a drill bit 226, a casing head 227 and a flow pipe 228 that carriesmud and other material to, for example, the mud tank 201.

In the example system of FIG. 2, a borehole 232 is formed in subsurfaceformations 230 by rotary drilling; noting that various exampleembodiments may also use directional drilling.

As shown in the example of FIG. 2, the drillstring 225 is suspendedwithin the borehole 232 and has a drillstring assembly 250 that includesthe drill bit 226 at its lower end. As an example, the drillstringassembly 250 may be a bottom hole assembly (BHA).

The wellsite system 200 can provide for operation of the drillstring 225and other operations. As shown, the wellsite system 200 includes theplatform 211 and the derrick 214 positioned over the borehole 232. Asmentioned, the wellsite system 200 can include the rotary table 220where the drillstring 225 pass through an opening in the rotary table220.

As shown in the example of FIG. 2, the wellsite system 200 can includethe kelly 218 and associated components, etc., or a top drive 240 andassociated components. As to a kelly example, the kelly 218 may be asquare or hexagonal metal/alloy bar with a hole drilled therein thatserves as a mud flow path. The kelly 218 can be used to transmit rotarymotion from the rotary table 220 via the kelly drive bushing 219 to thedrillstring 225, while allowing the drillstring 225 to be lowered orraised during rotation. The kelly 218 can pass through the kelly drivebushing 219, which can be driven by the rotary table 220. As an example,the rotary table 220 can include a master bushing that operativelycouples to the kelly drive bushing 219 such that rotation of the rotarytable 220 can turn the kelly drive bushing 219 and hence the kelly 218.The kelly drive bushing 219 can include an inside profile matching anoutside profile (e.g., square, hexagonal, etc.) of the kelly 218;however, with slightly larger dimensions so that the kelly 218 canfreely move up and down inside the kelly drive bushing 219.

As to a top drive example, the top drive 240 can provide functionsperformed by a kelly and a rotary table. The top drive 240 can turn thedrillstring 225. As an example, the top drive 240 can include one ormore motors (e.g., electric and/or hydraulic) connected with appropriategearing to a short section of pipe called a quill, that in turn may bescrewed into a saver sub or the drillstring 225 itself. The top drive240 can be suspended from the traveling block 211, so the rotarymechanism is free to travel up and down the derrick 214. As an example,a top drive 240 may allow for drilling to be performed with more jointstands than a kelly/rotary table approach.

In the example of FIG. 2, the mud tank 201 can hold mud, which can beone or more types of drilling fluids. As an example, a wellbore may bedrilled to produce fluid, inject fluid or both (e.g., hydrocarbons,minerals, water, etc.).

In the example of FIG. 2, the drillstring 225 (e.g., including one ormore downhole tools) may be composed of a series of pipes threadablyconnected together to form a long tube with the drill bit 226 at thelower end thereof. As the drillstring 225 is advanced into a wellborefor drilling, at some point in time prior to or coincident withdrilling, the mud may be pumped by the pump 204 from the mud tank 201(e.g., or other source) via a the lines 206, 208 and 209 to a port ofthe kelly 218 or, for example, to a port of the top drive 240. The mudcan then flow via a passage (e.g., or passages) in the drillstring 225and out of ports located on the drill bit 226 (see, e.g., a directionalarrow). As the mud exits the drillstring 225 via ports in the drill bit226, it can then circulate upwardly through an annular region between anouter surface(s) of the drillstring 225 and surrounding wall(s) (e.g.,open borehole, casing, etc.), as indicated by directional arrows. Insuch a manner, the mud lubricates the drill bit 226 and carries heatenergy (e.g., frictional or other energy) and formation cuttings to thesurface where the mud (e.g., and cuttings) may be returned to the mudtank 201, for example, for recirculation (e.g., with processing toremove cuttings, etc.).

The mud pumped by the pump 204 into the drillstring 225 may, afterexiting the drillstring 225, form a mudcake that lines the wellborewhich, among other functions, may reduce friction between thedrillstring 225 and surrounding wall(s) (e.g., borehole, casing, etc.).A reduction in friction may facilitate advancing or retracting thedrillstring 225. During a drilling operation, the entire drill string225 may be pulled from a wellbore and optionally replaced, for example,with a new or sharpened drill bit, a smaller diameter drill string, etc.As mentioned, the act of pulling a drill string out of a hole orreplacing it in a hole is referred to as tripping. A trip may bereferred to as an upward trip or an outward trip or as a downward tripor an inward trip depending on trip direction.

As an example, consider a downward trip where upon arrival of the drillbit 226 of the drill string 225 at a bottom of a wellbore, pumping ofthe mud commences to lubricate the drill bit 226 for purposes ofdrilling to enlarge the wellbore. As mentioned, the mud can be pumped bythe pump 204 into a passage of the drillstring 225 and, upon filling ofthe passage, the mud may be used as a transmission medium to transmitenergy, for example, energy that may encode information as in mud-pulsetelemetry.

As an example, mud-pulse telemetry equipment may include a downholedevice configured to effect changes in pressure in the mud to create anacoustic wave or waves upon which information may modulated. In such anexample, information from downhole equipment (e.g., one or more modulesof the drillstring 225) may be transmitted uphole to an uphole device,which may relay such information to other equipment for processing,control, etc.

As an example, telemetry equipment may operate via transmission ofenergy via the drillstring 225 itself. For example, consider a signalgenerator that imparts coded energy signals to the drillstring 225 andrepeaters that may receive such energy and repeat it to further transmitthe coded energy signals (e.g., information, etc.).

As an example, the drillstring 225 may be fitted with telemetryequipment 252 that includes a rotatable drive shaft, a turbine impellermechanically coupled to the drive shaft such that the mud can cause theturbine impeller to rotate, a modulator rotor mechanically coupled tothe drive shaft such that rotation of the turbine impeller causes saidmodulator rotor to rotate, a modulator stator mounted adjacent to orproximate to the modulator rotor such that rotation of the modulatorrotor relative to the modulator stator creates pressure pulses in themud, and a controllable brake for selectively braking rotation of themodulator rotor to modulate pressure pulses. In such example, analternator may be coupled to the aforementioned drive shaft where thealternator includes at least one stator winding electrically coupled toa control circuit to selectively short the at least one stator windingto electromagnetically brake the alternator and thereby selectivelybrake rotation of the modulator rotor to modulate the pressure pulses inthe mud.

In the example of FIG. 2, an uphole control and/or data acquisitionsystem 262 may include circuitry to sense pressure pulses generated bytelemetry equipment 252 and, for example, communicate sensed pressurepulses or information derived therefrom for process, control, etc.

The assembly 250 of the illustrated example includes alogging-while-drilling (LWD) module 254, a measuring-while-drilling(MWD) module 256, an optional module 258, a roto-steerable system andmotor 260, and the drill bit 226.

The LWD module 254 may be housed in a suitable type of drill collar andcan contain one or a plurality of selected types of logging tools. Itwill also be understood that more than one LWD and/or MWD module can beemployed, for example, as represented at by the module 256 of thedrillstring assembly 250. Where the position of an LWD module ismentioned, as an example, it may refer to a module at the position ofthe LWD module 254, the module 256, etc. An LWD module can includecapabilities for measuring, processing, and storing information, as wellas for communicating with the surface equipment. In the illustratedexample, the LWD module 254 may include a seismic measuring device.

The MWD module 256 may be housed in a suitable type of drill collar andcan contain one or more devices for measuring characteristics of thedrillstring 225 and the drill bit 226. As an example, the MWD tool 254may include equipment for generating electrical power, for example, topower various components of the drillstring 225. As an example, the MWDtool 254 may include the telemetry equipment 252, for example, where theturbine impeller can generate power by flow of the mud; it beingunderstood that other power and/or battery systems may be employed forpurposes of powering various components. As an example, the MWD module256 may include one or more of the following types of measuring devices:a weight-on-bit measuring device, a torque measuring device, a vibrationmeasuring device, a shock measuring device, a stick slip measuringdevice, a direction measuring device, and an inclination measuringdevice.

FIG. 2 also shows some examples of types of holes that may be drilled.For example, consider a slant hole 272, an S-shaped hole 274, a deepinclined hole 276 and a horizontal hole 278.

As an example, a drilling operation can include directional drillingwhere, for example, at least a portion of a well includes a curved axis.For example, consider a radius that defines curvature where aninclination with regard to the vertical may vary until reaching an anglebetween about 30 degrees and about 60 degrees or, for example, an angleto about 90 degrees or possibly greater than about 90 degrees.

As an example, a directional well can include several shapes where eachof the shapes may aim to meet particular operational demands. As anexample, a drilling process may be performed on the basis of informationas and when it is relayed to a drilling engineer. As an example,inclination and/or direction may be modified based on informationreceived during a drilling process.

As an example, deviation of a bore may be accomplished in part by use ofa downhole motor and/or a turbine. As to a motor, for example, adrillstring can include a positive displacement motor (PDM).

As an example, a system may be a steerable system and include equipmentto perform method such as geosteering. As an example, a steerable systemcan include a PDM or of a turbine on a lower part of a drillstringwhich, just above a drill bit, a bent sub can be mounted. As an example,above a PDM, MWD equipment that provides real time or near real timedata of interest (e.g., inclination, direction, pressure, temperature,real weight on the drill bit, torque stress, etc.) and/or LWD equipmentmay be installed. As to the latter, LWD equipment can make it possibleto send to the surface various types of data of interest, including forexample, geological data (e.g., gamma ray log, resistivity, density andsonic logs, etc.).

The coupling of sensors providing information on the course of a welltrajectory, in real time or near real time, with, for example, one ormore logs characterizing the formations from a geological viewpoint, canallow for implementing a geosteering method. Such a method can includenavigating a subsurface environment, for example, to follow a desiredroute to reach a desired target or targets.

As an example, a drillstring can include an azimuthal density neutron(AND) tool for measuring density and porosity; a MWD tool for measuringinclination, azimuth and shocks; a compensated dual resistivity (CDR)tool for measuring resistivity and gamma ray related phenomena; one ormore variable gauge stabilizers; one or more bend joints; and ageosteering tool, which may include a motor and optionally equipment formeasuring and/or responding to one or more of inclination, resistivityand gamma ray related phenomena.

As an example, geosteering can include intentional directional controlof a wellbore based on results of downhole geological loggingmeasurements in a manner that aims to keep a directional wellbore withina desired region, zone (e.g., a pay zone), etc. As an example,geosteering may include directing a wellbore to keep the wellbore in aparticular section of a reservoir, for example, to minimize gas and/orwater breakthrough and, for example, to maximize economic productionfrom a well that includes the wellbore.

Referring again to FIG. 2, the wellsite system 200 can include one ormore sensors 264 that are operatively coupled to the control and/or dataacquisition system 262. As an example, a sensor or sensors may be atsurface locations. As an example, a sensor or sensors may be at downholelocations. As an example, a sensor or sensors may be at one or moreremote locations that are not within a distance of the order of aboutone hundred meters from the wellsite system 200. As an example, a sensoror sensor may be at an offset wellsite where the wellsite system 200 andthe offset wellsite are in a common field (e.g., oil and/or gas field).

As an example, one or more of the sensors 264 can be provided fortracking pipe, tracking movement of at least a portion of a drillstring,etc.

As an example, the system 200 can include one or more sensors 266 thatcan sense and/or transmit signals to a fluid conduit such as a drillingfluid conduit (e.g., a drilling mud conduit). For example, in the system200, the one or more sensors 266 can be operatively coupled to portionsof the standpipe 208 through which mud flows. As an example, a downholetool can generate pulses that can travel through the mud and be sensedby one or more of the one or more sensors 266. In such an example, thedownhole tool can include associated circuitry such as, for example,encoding circuitry that can encode signals, for example, to reducedemands as to transmission. As an example, circuitry at the surface mayinclude decoding circuitry to decode encoded information transmitted atleast in part via mud-pulse telemetry. As an example, circuitry at thesurface may include encoder circuitry and/or decoder circuitry andcircuitry downhole may include encoder circuitry and/or decodercircuitry. As an example, the system 200 can include a transmitter thatcan generate signals that can be transmitted downhole via mud (e.g.,drilling fluid) as a transmission medium.

As an example, one or more portions of a drillstring may become stuck.The term stuck can refer to one or more of varying degrees of inabilityto move or remove a drillstring from a bore. As an example, in a stuckcondition, it might be possible to rotate pipe or lower it back into abore or, for example, in a stuck condition, there may be an inability tomove the drillstring axially in the bore, though some amount of rotationmay be possible. As an example, in a stuck condition, there may be aninability to move at least a portion of the drillstring axially androtationally.

As to the term “stuck pipe”, the can refer to a portion of a drillstringthat cannot be rotated or moved axially. As an example, a conditionreferred to as “differential sticking” can be a condition whereby thedrillstring cannot be moved (e.g., rotated or reciprocated) along theaxis of the bore. Differential sticking may occur when high-contactforces caused by low reservoir pressures, high wellbore pressures, orboth, are exerted over a sufficiently large area of the drillstring.Differential sticking can have time and financial cost.

As an example, a sticking force can be a product of the differentialpressure between the wellbore and the reservoir and the area that thedifferential pressure is acting upon. This means that a relatively lowdifferential pressure (delta p) applied over a large working area can bejust as effective in sticking pipe as can a high differential pressureapplied over a small area.

As an example, a condition referred to as “mechanical sticking” can be acondition where limiting or prevention of motion of the drillstring by amechanism other than differential pressure sticking occurs. Mechanicalsticking can be caused, for example, by one or more of junk in the hole,wellbore geometry anomalies, cement, keyseats or a buildup of cuttingsin the annulus.

FIG. 3 shows an example of a system 300 that includes various equipmentfor evaluation 310, planning 320, engineering 330 and operations 340.For example, a drilling workflow framework 301, a seismic-to-simulationframework 302, a technical data framework 303 and a drilling framework304 may be implemented to perform one or more processes such as aevaluating a formation 314, evaluating a process 318, generating atrajectory 324, validating a trajectory 328, formulating constraints334, designing equipment and/or processes based at least in part onconstraints 338, performing drilling 344 and evaluating drilling and/orformation 348.

In the example of FIG. 3, the seismic-to-simulation framework 302 canbe, for example, the PETREL® framework (Schlumberger Limited, Houston,Tex.) and the technical data framework 303 can be, for example, theTECHLOG® framework (Schlumberger Limited, Houston, Tex.).

As an example, a framework can include entities that may include earthentities, geological objects or other objects such as wells, surfaces,reservoirs, etc. Entities can include virtual representations of actualphysical entities that are reconstructed for purposes of one or more ofevaluation, planning, engineering, operations, etc.

Entities may include entities based on data acquired via sensing,observation, etc. (e.g., seismic data and/or other information). Anentity may be characterized by one or more properties (e.g., ageometrical pillar grid entity of an earth model may be characterized bya porosity property). Such properties may represent one or moremeasurements (e.g., acquired data), calculations, etc.

A framework may be an object-based framework. In such a framework,entities may include entities based on pre-defined classes, for example,to facilitate modeling, analysis, simulation, etc. A commerciallyavailable example of an object-based framework is the MICROSOFT™.NET™framework (Redmond, Wash.), which provides a set of extensible objectclasses. In the .NET™ framework, an object class encapsulates a moduleof reusable code and associated data structures. Object classes can beused to instantiate object instances for use in by a program, script,etc. For example, borehole classes may define objects for representingboreholes based on well data.

As an example, a framework can include an analysis component that mayallow for interaction with a model or model-based results (e.g.,simulation results, etc.). As to simulation, a framework may operativelylink to or include a simulator such as the ECLIPSE® reservoir simulator(Schlumberger Limited, Houston Tex.), the INTERSECT® reservoir simulator(Schlumberger Limited, Houston Tex.), etc.

The aforementioned PETREL® framework provides components that allow foroptimization of exploration and development operations. The PETREL®framework includes seismic to simulation software components that canoutput information for use in increasing reservoir performance, forexample, by improving asset team productivity. Through use of such aframework, various professionals (e.g., geophysicists, geologists, wellengineers, reservoir engineers, etc.) can develop collaborativeworkflows and integrate operations to streamline processes. Such aframework may be considered an application and may be considered adata-driven application (e.g., where data is input for purposes ofmodeling, simulating, etc.).

As an example, one or more frameworks may be interoperative and/or runupon one or another. As an example, consider the commercially availableframework environment marketed as the OCEAN® framework environment(Schlumberger Limited, Houston, Tex.), which allows for integration ofadd-ons (or plug-ins) into a PETREL® framework workflow. The OCEAN®framework environment leverages .NET™ tools (Microsoft Corporation,Redmond, Wash.) and offers stable, user-friendly interfaces forefficient development. In an example embodiment, various components maybe implemented as add-ons (or plug-ins) that conform to and operateaccording to specifications of a framework environment (e.g., accordingto application programming interface (API) specifications, etc.).

As an example, a framework can include a model simulation layer alongwith a framework services layer, a framework core layer and a moduleslayer. The framework may include the commercially available OCEAN®framework where the model simulation layer can include or operativelylink to the commercially available PETREL® model-centric softwarepackage that hosts OCEAN® framework applications. In an exampleembodiment, the PETREL® software may be considered a data-drivenapplication. The PETREL® software can include a framework for modelbuilding and visualization. Such a model may include one or more grids.

As an example, the model simulation layer may provide domain objects,act as a data source, provide for rendering and provide for various userinterfaces. Rendering may provide a graphical environment in whichapplications can display their data while the user interfaces mayprovide a common look and feel for application user interfacecomponents.

As an example, domain objects can include entity objects, propertyobjects and optionally other objects. Entity objects may be used togeometrically represent wells, surfaces, reservoirs, etc., whileproperty objects may be used to provide property values as well as dataversions and display parameters. For example, an entity object mayrepresent a well where a property object provides log information aswell as version information and display information (e.g., to displaythe well as part of a model).

As an example, data may be stored in one or more data sources (or datastores, generally physical data storage devices), which may be at thesame or different physical sites and accessible via one or morenetworks. As an example, a model simulation layer may be configured tomodel projects. As such, a particular project may be stored where storedproject information may include inputs, models, results and cases. Thus,upon completion of a modeling session, a user may store a project. At alater time, the project can be accessed and restored using the modelsimulation layer, which can recreate instances of the relevant domainobjects.

As an example, the system 300 may be used to perform one or moreworkflows. A workflow may be a process that includes a number ofworksteps. A workstep may operate on data, for example, to create newdata, to update existing data, etc. As an example, a workflow mayoperate on one or more inputs and create one or more results, forexample, based on one or more algorithms. As an example, a system mayinclude a workflow editor for creation, editing, executing, etc. of aworkflow. In such an example, the workflow editor may provide forselection of one or more pre-defined worksteps, one or more customizedworksteps, etc. As an example, a workflow may be a workflowimplementable at least in part in the PETREL® software, for example,that operates on seismic data, seismic attribute(s), etc.

As an example, seismic data can be data acquired via a seismic surveywhere sources and receivers are positioned in a geologic environment toemit and receive seismic energy where at least a portion of such energycan reflect off subsurface structures. As an example, a seismic dataanalysis framework or frameworks (e.g., consider the OMEGA® framework,marketed by Schlumberger Limited, Houston, Tex.) may be utilized todetermine depth, extent, properties, etc. of subsurface structures. Asan example, seismic data analysis can include forward modeling and/orinversion, for example, to iteratively build a model of a subsurfaceregion of a geologic environment. As an example, a seismic data analysisframework may be part of or operatively coupled to aseismic-to-simulation framework (e.g., the PETREL® framework, etc.).

As an example, a workflow may be a process implementable at least inpart in the OCEAN® framework. As an example, a workflow may include oneor more worksteps that access a module such as a plug-in (e.g., externalexecutable code, etc.).

As an example, a framework may provide for modeling petroleum systems.For example, the commercially available modeling framework marketed asthe PETROMOD® framework (Schlumberger Limited, Houston, Tex.) includesfeatures for input of various types of information (e.g., seismic, well,geological, etc.) to model evolution of a sedimentary basin. ThePETROMOD® framework provides for petroleum systems modeling via input ofvarious data such as seismic data, well data and other geological data,for example, to model evolution of a sedimentary basin. The PETROMOD®framework may predict if, and how, a reservoir has been charged withhydrocarbons, including, for example, the source and timing ofhydrocarbon generation, migration routes, quantities, pore pressure andhydrocarbon type in the subsurface or at surface conditions. Incombination with a framework such as the PETREL® framework, workflowsmay be constructed to provide basin-to-prospect scale explorationsolutions. Data exchange between frameworks can facilitate constructionof models, analysis of data (e.g., PETROMOD® framework data analyzedusing PETREL® framework capabilities), and coupling of workflows.

As mentioned, a drillstring can include various tools that may makemeasurements. As an example, a wireline tool or another type of tool maybe utilized to make measurements. As an example, a tool may beconfigured to acquire electrical borehole images. As an example, thefullbore Formation MicroImager (FMI) tool (Schlumberger Limited,Houston, Tex.) can acquire borehole image data. A data acquisitionsequence for such a tool can include running the tool into a boreholewith acquisition pads closed, opening and pressing the pads against awall of the borehole, delivering electrical current into the materialdefining the borehole while translating the tool in the borehole, andsensing current remotely, which is altered by interactions with thematerial.

Analysis of formation information may reveal features such as, forexample, vugs, dissolution planes (e.g., dissolution along beddingplanes), stress-related features, dip events, etc. As an example, a toolmay acquire information that may help to characterize a reservoir,optionally a fractured reservoir where fractures may be natural and/orartificial (e.g., hydraulic fractures). As an example, informationacquired by a tool or tools may be analyzed using a framework such asthe TECHLOG® framework. As an example, the TECHLOG® framework can beinteroperable with one or more other frameworks such as, for example,the PETREL® framework.

FIG. 4 shows an example of a system 400 that includes a client layer410, an applications layer 440 and a storage layer 460. As shown theclient layer 410 can be in communication with the applications layer 440and the applications layer 440 can be in communication with the storagelayer 460.

The client layer 410 can include features that allow for access andinteractions via one or more private networks 412, one or more mobileplatforms and/or mobile networks 414 and via the “cloud” 416, which maybe considered to include distributed equipment that forms a network suchas a network of networks.

In the example of FIG. 4, the applications layer 440 includes thedrilling workflow framework 301 as mentioned with respect to the exampleof FIG. 3. The applications layer 440 also includes a databasemanagement component 442 that includes one or more search enginesmodules.

As an example, the database management component 442 can include one ormore search engine modules that provide for searching one or moreinformation that may be stored in one or more data repositories. As anexample, the STUDIO E&P™ knowledge environment (Schlumberger Ltd.,Houston, Tex.) includes STUDIO FIND™ search functionality, whichprovides a search engine. The STUDIO FIND™ search functionality alsoprovides for indexing content, for example, to create one or moreindexes. As an example, search functionality may provide for access topublic content, private content or both, which may exist in one or moredatabases, for example, optionally distributed and accessible via anintranet, the Internet or one or more other networks. As an example, asearch engine may be configured to apply one or more filters from a setor sets of filters, for example, to enable users to filter out data thatmay not be of interest.

As an example, a framework may provide for interaction with a searchengine and, for example, associated features such as features of theSTUDIO FIND™ search functionality. As an example, a framework mayprovide for implementation of one or more spatial filters (e.g., basedon an area viewed on a display, static data, etc.). As an example, asearch may provide access to dynamic data (e.g., “live” data from one ormore sources), which may be available via one or more networks (e.g.,wired, wireless, etc.). As an example, one or more modules mayoptionally be implemented within a framework or, for example, in amanner operatively coupled to a framework (e.g., as an add-on, aplug-in, etc.). As an example, a module for structuring search results(e.g., in a list, a hierarchical tree structure, etc.) may optionally beimplemented within a framework or, for example, in a manner operativelycoupled to a framework (e.g., as an add-on, a plug-in, etc.).

In the example of FIG. 4, the applications layer 440 can includecommunicating with one or more resources such as, for example, theseismic-to-simulation framework 302, the drilling framework 304 and/orone or more sites, which may be or include one or more offset wellsites.As an example, the applications layer 440 may be implemented for aparticular wellsite where information can be processed as part of aworkflow for operations such as, for example, operations performed,being performed and/or to be performed at the particular wellsite. As anexample, an operation may involve directional drilling, for example, viageosteering.

In the example of FIG. 4, the storage layer 460 can include varioustypes of data, information, etc., which may be stored in one or moredatabases 462. As an example, one or more servers 464 may provide formanagement, access, etc., to data, information, etc., stored in the oneor more databases 462. As an example, the module 442 may provide forsearching as to data, information, etc., stored in the one or moredatabases 462.

As an example, the module 442 may include features for indexing, etc. Asan example, information may be indexed at least in part with respect towellsite. For example, where the applications layer 440 is implementedto perform one or more workflows associated with a particular wellsite,data, information, etc., associated with that particular wellsite may beindexed based at least in part on the wellsite being an index parameter(e.g., a search parameter).

As an example, the system 400 of FIG. 4 may be implemented to performone or more portions of one or more workflows associated with the system300 of FIG. 3. For example, the drilling workflow framework 301 mayinteract with the technical data framework 303 and the drillingframework 304 before, during and/or after performance of one or moredrilling operations. In such an example, the one or more drillingoperations may be performed in a geologic environment (see, e.g., theenvironment 150 of FIG. 1) using one or more types of equipment (see,e.g., equipment of FIGS. 1 and 2).

FIG. 5 shows an example of a system 500 that includes a computing device501, an application services block 510, a bootstrap services block 520,a cloud gateway block 530, a cloud portal block 540, a stream processingservices block 550, one or more databases 560, a management servicesblock 570 and a service systems manager 590.

In the example of FIG. 5, the computing device 501 can include one ormore processors 502, memory 503, one or more interfaces 504 and locationcircuitry 505 or, for example, one of the one or more interfaces 504 maybe operatively coupled to location circuitry that can acquire locallocation information. For example, the computing device 501 can includeGPS circuitry as location circuitry such that the approximate locationof the computer device 501 can be determined. While GPS is mentioned(Global Positioning System), location circuitry may employ one or moretypes of locating techniques. For example, consider one or more ofGLONASS, GALILEO, BeiDou-2, or another system (e.g., global navigationsatellite system, “GNSS”). As an example, location circuitry may includecellular phone circuitry (e.g., LTE, 3G, 4G, etc.). As an example,location circuitry may include WiFi circuitry.

As an example, the application services block 510 can be implemented viainstructions executable using the computing device 501. As an example,the computing device 501 may be at a wellsite and part of wellsiteequipment. As an example, the computing device 501 may be a mobilecomputing device (e.g., tablet, laptop, etc.) or a desktop computingdevice that may be mobile, for example, as part of wellsite equipment(e.g., doghouse equipment, rig equipment, vehicle equipment, etc.).

As an example, the system 500 can include performing various actions.For example, the system 500 may include a token that is utilized as asecurity measure to assure that information (e.g., data) is associatedwith appropriate permission or permissions for transmission, storage,access, etc.

In the example of FIG. 5, various circles are shown with labels A to H.As an example, A can be a process where an administrator creates ashared access policy (e.g., manually, via an API, etc.); B can be aprocess for allocating a shared access key for a device identifier(e.g., a device ID), which may be performed manually, via an API, etc.);C can be a process for creating a “device” that can be registered in adevice registry and for allocating a symmetric key; D can be a processfor persisting metadata where such metadata may be associated with awellsite identifier (e.g., a well ID) and where, for example, locationinformation (e.g., GPS based information, etc.) may be associated with adevice ID and a well ID; E can be a process where a bootstrap messagepasses that includes a device ID (e.g., a trusted platform module (TPM)chip ID that may be embedded within a device) and that includes a wellID and location information such that bootstrap services (e.g., of thebootstrap services block 520) can proceed to obtain shared accesssignature (SAS) key(s) to a cloud service endpoint for authorization; Fcan be a process for provisioning a device, for example, if not alreadyprovisioned, where, for example, the process can include returningdevice keys and endpoint; G can be a process for getting a SAS tokenusing an identifier and a key; and H can be a process that includesbeing ready to send a message using device credentials. Also shown inFIG. 5 is a process for getting a token and issuing a command for a wellidentifier (see label Z).

As an example, Shared Access Signatures can be an authenticationmechanism based on, for example, SHA-256 secure hashes, URIs, etc. As anexample, SAS may be used by one or more Service Bus services. SAS can beimplemented via a Shared Access Policy and a Shared Access Signature,which may be referred to as a token. As an example, for SAS applicationsusing the AZURE™.NET SDK with the Service Bus, .NET libraries can useSAS authorization through the SharedAccessSignatureTokenProvider class.

As an example, where a system gives an entity (e.g., a sender, a client,etc.) a SAS token, that entity does not have the key directly, and thatentity cannot reverse the hash to obtain it. As such, there is controlover what that entity can access and, for example, for how long accessmay exist. As an example, in SAS, for a change of the primary key in thepolicy, Shared Access Signatures created from it will be invalidated.

As an example, the system 500 of FIG. 5 can be implemented forprovisioning of rig acquisition system and/or data delivery.

As an example, a method can include establishing an Internet of Things(IoT) hub or hubs. As an example, such a hub or hubs can include one ormore device registries. In such an example, the hub or hubs may providefor storage of metadata associated with a device and, for example, aper-device authentication model. As an example, where locationinformation indicates that a device (e.g., wellsite equipment, etc.) hasbeen changed with respect to its location, a method can include revokingthe device in a hub.

As an example, an architecture utilized in a system such as, forexample, the system 500, may include features of the AZURE™ architecture(Microsoft Corporation, Redmond, Wash.). As an example, the cloud portalblock 540 can include one or more features of an AZURE™ portal that canmanage, mediate, etc. access to one or more services, data, connections,networks, devices, etc.

As an example, the system 500 can include a cloud computing platform andinfrastructure, for example, for building, deploying, and managingapplications and services (e.g., through a network of datacenters,etc.). As an example, such a cloud platform may provide PaaS and IaaSservices and support one or more different programming languages, toolsand frameworks, etc.

FIG. 6 shows an example of a system 600 associated with an example of awellsite system 601 and also shows an example scenario 602. As shown inFIG. 6, the system 600 can include a front-end 603 and a back-end 605from an outside or external perspective (e.g., external to the wellsitesystem 601, etc.). In the example of FIG. 6, the system 600 includes adrilling framework 620, a stream processing and/or management block 640,storage 660 and optionally one or more other features that can bedefined as being back-end features. In the example of FIG. 6, the system600 includes a drilling workflow framework 610, a stream processingand/or management block 630, applications 650 and optionally one or moreother features that can be defined as being front-end features.

As an example, a user operating a user device can interact with thefront-end 603 where the front-end 603 can interact with one or morefeatures of the back-end 605. As an example, such interactions may beimplemented via one or more networks, which may be associated with acloud platform (e.g., cloud resources, etc.).

As to the example scenario 602, the drilling framework 620 can provideinformation associated with, for example, the wellsite system 601. Asshown, the stream blocks 630 and 640, a query service 685 and thedrilling workflow framework 610 may receive information and direct suchinformation to storage, which may include a time series database 662, ablob storage database 664, a document database 666, a well informationdatabase 668, a project(s) database 669, etc. As an example, the wellinformation database 668 may receive and store information such as, forexample, customer information (e.g., from entities that may be owners ofrights at a wellsite, service providers at a wellsite, etc.). As anexample, the project database 669 can include information from aplurality of projects where a project may be, for example, a wellsiteproject.

As an example, the system 600 can be operable for a plurality ofwellsites, which may include active and/or inactive wellsites and/or,for example, one or more planned wellsites. As an example, the system600 can include various components of the system 300 of FIG. 3. As anexample, the system 600 can include various components of the system 400of FIG. 4. For example, the drilling workflow framework 610 can be adrilling workflow framework such as the drilling workflow framework 301and/or, for example, the drilling framework 620 can be a drillingframework such as the drilling framework 304.

FIG. 7 shows an example of a wellsite system 700, specifically, FIG. 7shows the wellsite system 700 in an approximate side view and anapproximate plan view along with a block diagram of a system 770.

In the example of FIG. 7, the wellsite system 700 can include a cabin710, a rotary table 722, drawworks 724, a mast 726 (e.g., optionallycarrying a top drive, etc.), mud tanks 730 (e.g., with one or morepumps, one or more shakers, etc.), one or more pump buildings 740, aboiler building 742, an HPU building 744 (e.g., with a rig fuel tank,etc.), a combination building 748 (e.g., with one or more generators,etc.), pipe tubs 762, a catwalk 764, a flare 768, etc. Such equipmentcan include one or more associated functions and/or one or moreassociated operational risks, which may be risks as to time, resources,and/or humans.

As shown in the example of FIG. 7, the wellsite system 700 can include asystem 770 that includes one or more processors 772, memory 774operatively coupled to at least one of the one or more processors 772,instructions 776 that can be, for example, stored in the memory 774, andone or more interfaces 778. As an example, the system 770 can includeone or more processor-readable media that include processor-executableinstructions executable by at least one of the one or more processors772 to cause the system 770 to control one or more aspects of thewellsite system 700. In such an example, the memory 774 can be orinclude the one or more processor-readable media where theprocessor-executable instructions can be or include instructions. As anexample, a processor-readable medium can be a computer-readable storagemedium that is not a signal and that is not a carrier wave.

FIG. 7 also shows a battery 780 that may be operatively coupled to thesystem 770, for example, to power the system 770. As an example, thebattery 780 may be a back-up battery that operates when another powersupply is unavailable for powering the system 770. As an example, thebattery 780 may be operatively coupled to a network, which may be acloud network. As an example, the battery 780 can include smart batterycircuitry and may be operatively coupled to one or more pieces ofequipment via a SMBus or other type of bus.

In the example of FIG. 7, services 790 are shown as being available, forexample, via a cloud platform. Such services can include data services792, query services 794 and drilling services 796. As an example, theservices 790 may be part of a system such as the system 300 of FIG. 3,the system 400 of FIG. 4 and/or the system 600 of FIG. 6.

As an example, a system such as, for example, the system 300 of FIG. 3may be utilized to perform a workflow. Such a system may be distributedand allow for collaborative workflow interactions and may be consideredto be a platform (e.g., a framework for collaborative interactions,etc.).

As an example, one or more systems can be utilized to implement aworkflow that can be performed collaboratively. As an example, thesystem 300 of FIG. 3 can be operated as a distributed, collaborativewell-planning system. The system 300 can utilize one or more servers,one or more client devices, etc. and may maintain one or more databases,data files, etc., which may be accessed and modified by one or moreclient devices, for example, using a web browser, remote terminal, etc.As an example, a client device may modify a database or data fileson-the-fly, and/or may include “sandboxes” that may permit one or moreclient devices to modify at least a portion of a database or data filesoptionally off-line, for example, without affecting a database or datafiles seen by one or more other client devices. As an example, a clientdevice that includes a sandbox may modify a database or data file aftercompleting an activity in the sandbox.

In some examples, client devices and/or servers may be remote withrespect to one another and/or may individually include two or moreremote processing units. As an example, two systems can be “remote” withrespect to one another if they are not physically proximate to oneanother; for example, two devices that are located at different sides ofa room, in different rooms, in different buildings, in different cities,countries, etc. may be considered “remote” depending on the context. Insome embodiments, two or more client devices may be proximate to oneanother, and/or one or more client devices and a server may be proximateto one another.

As an example, various aspects of a workflow may be completedautomatically, may be partially automated, or may be completed manually,as by a human user interfacing with a software application. As anexample, a workflow may be cyclic, and may include, as an example, fourstages such as, for example, an evaluation stage (see, e.g., theevaluation equipment 310), a planning stage (see, e.g., the planningequipment 320), an engineering stage (see, e.g., the engineeringequipment 330) and an execution stage (see, e.g., the operationsequipment 340). As an example, a workflow may commence at one or morestages, which may progress to one or more other stages (e.g., in aserial manner, in a parallel manner, in a cyclical manner, etc.).

As an example, a workflow can commence with an evaluation stage, whichmay include a geological service provider evaluating a formation (see,e.g., the evaluation block 314). As an example, a geological serviceprovider may undertake the formation evaluation using a computing systemexecuting a software package tailored to such activity; or, for example,one or more other suitable geology platforms may be employed (e.g.,alternatively or additionally). As an example, the geological serviceprovider may evaluate the formation, for example, using earth models,geophysical models, basin models, petrotechnical models, combinationsthereof, and/or the like. Such models may take into consideration avariety of different inputs, including offset well data, seismic data,pilot well data, other geologic data, etc. The models and/or the inputmay be stored in the database maintained by the server and accessed bythe geological service provider.

As an example, a workflow may progress to a geology and geophysics(“G&G”) service provider, which may generate a well trajectory (see,e.g., the generation block 324), which may involve execution of one ormore G&G software packages. Examples of such software packages includethe PETREL® framework. As an example, a G&G service provider maydetermine a well trajectory or a section thereof, based on, for example,one or more model(s) provided by a formation evaluation (e.g., per theevaluation block 314), and/or other data, e.g., as accessed from one ormore databases (e.g., maintained by one or more servers, etc.). As anexample, a well trajectory may take into consideration various “basis ofdesign” (BOD) constraints, such as general surface location, target(e.g., reservoir) location, and the like. As an example, a trajectorymay incorporate information about tools, bottom-hole assemblies, casingsizes, etc., that may be used in drilling the well. A well trajectorydetermination may take into consideration a variety of other parameters,including risk tolerances, fluid weights and/or plans, bottom-holepressures, drilling time, etc.

As an example, a workflow may progress to a first engineering serviceprovider (e.g., one or more processing machines associated therewith),which may validate a well trajectory and, for example, relief welldesign (see, e.g., the validation block 328). Such a validation processmay include evaluating physical properties, calculations, risktolerances, integration with other aspects of a workflow, etc. As anexample, one or more parameters for such determinations may bemaintained by a server and/or by the first engineering service provider;noting that one or more model(s), well trajectory(ies), etc. may bemaintained by a server and accessed by the first engineering serviceprovider. For example, the first engineering service provider mayinclude one or more computing systems executing one or more softwarepackages. As an example, where the first engineering service providerrejects or otherwise suggests an adjustment to a well trajectory, thewell trajectory may be adjusted or a message or other notification sentto the G&G service provider requesting such modification.

As an example, one or more engineering service providers (e.g., first,second, etc.) may provide a casing design, bottom-hole assembly (BHA)design, fluid design, and/or the like, to implement a well trajectory(see, e.g., the design block 338). In some embodiments, a secondengineering service provider may perform such design using one of moresoftware applications. Such designs may be stored in one or moredatabases maintained by one or more servers, which may, for example,employ STUDIO® framework tools, and may be accessed by one or more ofthe other service providers in a workflow.

As an example, a second engineering service provider may seek approvalfrom a third engineering service provider for one or more designsestablished along with a well trajectory. In such an example, the thirdengineering service provider may consider various factors as to whetherthe well engineering plan is acceptable, such as economic variables(e.g., oil production forecasts, costs per barrel, risk, drill time,etc.), and may request authorization for expenditure, such as from theoperating company's representative, well-owner's representative, or thelike (see, e.g., the formulation block 334). As an example, at leastsome of the data upon which such determinations are based may be storedin one or more database maintained by one or more servers. As anexample, a first, a second, and/or a third engineering service providermay be provided by a single team of engineers or even a single engineer,and thus may or may not be separate entities.

As an example, where economics may be unacceptable or subject toauthorization being withheld, an engineering service provider maysuggest changes to casing, a bottom-hole assembly, and/or fluid design,or otherwise notify and/or return control to a different engineeringservice provider, so that adjustments may be made to casing, abottom-hole assembly, and/or fluid design. Where modifying one or moreof such designs is impracticable within well constraints, trajectory,etc., the engineering service provider may suggest an adjustment to thewell trajectory and/or a workflow may return to or otherwise notify aninitial engineering service provider and/or a G&G service provider suchthat either or both may modify the well trajectory.

As an example, a workflow can include considering a well trajectory,including an accepted well engineering plan, and a formation evaluation.Such a workflow may then pass control to a drilling service provider,which may implement the well engineering plan, establishing safe andefficient drilling, maintaining well integrity, and reporting progressas well as operating parameters (see, e.g., the blocks 344 and 348). Asan example, operating parameters, formation encountered, data collectedwhile drilling (e.g., using logging-while-drilling ormeasuring-while-drilling technology), may be returned to a geologicalservice provider for evaluation. As an example, the geological serviceprovider may then re-evaluate the well trajectory, or one or more otheraspects of the well engineering plan, and may, in some cases, andpotentially within predetermined constraints, adjust the wellengineering plan according to the real-life drilling parameters (e.g.,based on acquired data in the field, etc.).

Whether the well is entirely drilled, or a section thereof is completed,depending on the specific embodiment, a workflow may proceed to a postreview (see, e.g., the evaluation block 318). As an example, a postreview may include reviewing drilling performance. As an example, a postreview may further include reporting the drilling performance (e.g., toone or more relevant engineering, geological, or G&G service providers).

Various activities of a workflow may be performed consecutively and/ormay be performed out of order (e.g., based partially on information fromtemplates, nearby wells, etc. to fill in any gaps in information that isto be provided by another service provider). As an example, undertakingone activity may affect the results or basis for another activity, andthus may, either manually or automatically, call for a variation in oneor more workflow activities, work products, etc. As an example, a servermay allow for storing information on a central database accessible tovarious service providers where variations may be sought bycommunication with an appropriate service provider, may be madeautomatically, or may otherwise appear as suggestions to the relevantservice provider. Such an approach may be considered to be a holisticapproach to a well workflow, in comparison to a sequential, piecemealapproach.

As an example, various actions of a workflow may be repeated multipletimes during drilling of a wellbore. For example, in one or moreautomated systems, feedback from a drilling service provider may beprovided at or near real-time, and the data acquired during drilling maybe fed to one or more other service providers, which may adjust itspiece of the workflow accordingly. As there may be dependencies in otherareas of the workflow, such adjustments may permeate through theworkflow, e.g., in an automated fashion. In some embodiments, a cyclicprocess may additionally or instead proceed after a certain drillinggoal is reached, such as the completion of a section of the wellbore,and/or after the drilling of the entire wellbore, or on a per-day, week,month, etc. basis.

Well planning can include determining a path of a well that can extendto a reservoir, for example, to economically produce fluids such ashydrocarbons therefrom. Well planning can include selecting a drillingand/or completion assembly which may be used to implement a well plan.As an example, various constraints can be imposed as part of wellplanning that can impact design of a well. As an example, suchconstraints may be imposed based at least in part on information as toknown geology of a subterranean domain, presence of one or more otherwells (e.g., actual and/or planned, etc.) in an area (e.g., considercollision avoidance), etc. As an example, one or more constraints may beimposed based at least in part on characteristics of one or more tools,components, etc. As an example, one or more constraints may be based atleast in part on factors associated with drilling time and/or risktolerance.

As an example, a system can allow for a reduction in waste, for example,as may be defined according to LEAN. In the context of LEAN, considerone or more of the following types of waste: Transport (e.g., movingitems unnecessarily, whether physical or data); Inventory (e.g.,components, whether physical or informational, as work in process, andfinished product not being processed); Motion (e.g., people or equipmentmoving or walking unnecessarily to perform desired processing); Waiting(e.g., waiting for information, interruptions of production during shiftchange, etc.); Overproduction (e.g., production of material,information, equipment, etc. ahead of demand); Over Processing (e.g.,resulting from poor tool or product design creating activity); andDefects (e.g., effort involved in inspecting for and fixing defectswhether in a plan, data, equipment, etc.). As an example, a system thatallows for actions (e.g., methods, workflows, etc.) to be performed in acollaborative manner can help to reduce one or more types of waste.

As an example, a system can be utilized to implement a method forfacilitating distributed well engineering, planning, and/or drillingsystem design across multiple computation devices where collaborationcan occur among various different users (e.g., some being local, somebeing remote, some being mobile, etc.). In such a system, the varioususers via appropriate devices may be operatively coupled via one or morenetworks (e.g., local and/or wide area networks, public and/or privatenetworks, land-based, marine-based and/or areal networks, etc.).

As an example, a system may allow well engineering, planning, and/ordrilling system design to take place via a subsystems approach where awellsite system is composed of various subsystem, which can includeequipment subsystems and/or operational subsystems (e.g., controlsubsystems, etc.). As an example, computations may be performed usingvarious computational platforms/devices that are operatively coupled viacommunication links (e.g., network links, etc.). As an example, one ormore links may be operatively coupled to a common database (e.g., aserver site, etc.). As an example, a particular server or servers maymanage receipt of notifications from one or more devices and/or issuanceof notifications to one or more devices. As an example, a system may beimplemented for a project where the system can output a well plan, forexample, as a digital well plan, a paper well plan, a digital and paperwell plan, etc. Such a well plan can be a complete well engineering planor design for the particular project.

FIG. 8 shows a schematic diagram depicting an example of a drillingoperation of a directional well in multiple sections. The drillingoperation depicted in FIG. 8 includes a wellsite drilling system 800 anda field management tool 820 for managing various operations associatedwith drilling a bore hole 850 of a directional well 817. The wellsitedrilling system 800 includes various components (e.g., drillstring 812,annulus 813, bottom hole assembly (BHA) 814, kelly 815, mud pit 816,etc.). As shown in the example of FIG. 8, a target reservoir may belocated away from (as opposed to directly under) the surface location ofthe well 817. In such an example, special tools or techniques may beused to ensure that the path along the bore hole 850 reaches theparticular location of the target reservoir.

As an example, the BHA 814 may include sensors 808, a rotary steerablesystem 809, and a bit 810 to direct the drilling toward the targetguided by a pre-determined survey program for measuring location detailsin the well. Furthermore, the subterranean formation through which thedirectional well 817 is drilled may include multiple layers (not shown)with varying compositions, geophysical characteristics, and geologicalconditions. Both the drilling planning during the well design stage andthe actual drilling according to the drilling plan in the drilling stagemay be performed in multiple sections (e.g., sections 801, 802, 803 and804) corresponding to the multiple layers in the subterranean formation.For example, certain sections (e.g., sections 801 and 802) may usecement 807 reinforced casing 806 due to the particular formationcompositions, geophysical characteristics, and geological conditions.

In the example of FIG. 8, a surface unit 811 may be operatively linkedto the wellsite drilling system 800 and the field management tool 820via communication links 818. The surface unit 811 may be configured withfunctionalities to control and monitor the drilling activities bysections in real-time via the communication links 818. The fieldmanagement tool 820 may be configured with functionalities to storeoilfield data (e.g., historical data, actual data, surface data,subsurface data, equipment data, geological data, geophysical data,target data, anti-target data, etc.) and determine relevant factors forconfiguring a drilling model and generating a drilling plan. Theoilfield data, the drilling model, and the drilling plan may betransmitted via the communication link 818 according to a drillingoperation workflow. The communication links 818 may include acommunication subassembly.

During various operations at a wellsite, data can be acquired foranalysis and/or monitoring of one or more operations. Such data mayinclude, for example, subterranean formation, equipment, historicaland/or other data. Static data can relate to, for example, formationstructure and geological stratigraphy that define the geologicalstructures of the subterranean formation. Static data may also includedata about a bore, such as inside diameters, outside diameters, anddepths. Dynamic data can relate to, for example, fluids flowing throughthe geologic structures of the subterranean formation over time. Thedynamic data may include, for example, pressures, fluid compositions(e.g. gas oil ratio, water cut, and/or other fluid compositionalinformation), and states of various equipment, and other information.

The static and dynamic data collected via a bore, a formation,equipment, etc. may be used to create and/or update a three dimensionalmodel of one or more subsurface formations. As an example, static anddynamic data from one or more other bores, fields, etc. may be used tocreate and/or update a three dimensional model. As an example, hardwaresensors, core sampling, and well logging techniques may be used tocollect data. As an example, static measurements may be gathered usingdownhole measurements, such as core sampling and well loggingtechniques. Well logging involves deployment of a downhole tool into thewellbore to collect various downhole measurements, such as density,resistivity, etc., at various depths. Such well logging may be performedusing, for example, a drilling tool and/or a wireline tool, or sensorslocated on downhole production equipment. Once a well is formed andcompleted, depending on the purpose of the well (e.g., injection and/orproduction), fluid may flow to the surface (e.g., and/or from thesurface) using tubing and other completion equipment. As fluid passes,various dynamic measurements, such as fluid flow rates, pressure, andcomposition may be monitored. These parameters may be used to determinevarious characteristics of a subterranean formation, downhole equipment,downhole operations, etc.

To facilitate the processing and analysis of data, simulators may beused to process data. Data fed into the simulator(s) may be historicaldata, real time data or combinations thereof. Simulation through one ormore of the simulators may be repeated or adjusted based on the datareceived. As an example, oilfield operations can be provided withwellsite and non-wellsite simulators. The wellsite simulators mayinclude a reservoir simulator, a wellbore simulator, and a surfacenetwork simulator. The reservoir simulator may solve for hydrocarbonflowrate through the reservoir and into the wellbores. The wellboresimulator and surface network simulator may solve for hydrocarbonflowrate through the wellbore and the surface gathering network ofpipelines.

FIG. 9 shows an example of a system 900 that includes various componentsthat can be local to a wellsite and includes various components that canbe remote from a wellsite. As shown, the system 900 includes a Maestroblock 902, an Opera block 904, a Core & Services block 906 and anEquipment block 908. These blocks can be labeled in one or more mannersother than as shown in the example of FIG. 9. In the example of FIG. 9,the blocks 902, 904, 906 and 908 can be defined by one or more ofoperational features, functions, relationships in an architecture, etc.

As an example, the blocks 902, 904, 906 and 908 may be described in apyramidal architecture where, from peak to base, a pyramid includes theMaestro block 902, the Opera block 904, the Core & Services block 906and the Equipment block 908.

As an example, the Maestro block 902 can be associated with a wellmanagement level (e.g., well planning and/or orchestration) and can beassociated with a rig management level (e.g., rig dynamic planningand/or orchestration). As an example, the Opera block 904 can beassociated with a process management level (e.g., rig integratedexecution). As an example, the Core & Services block 906 can beassociated with a data management level (e.g., sensor, instrumentation,inventory, etc.). As an example, the Equipment block 908 can beassociated with a wellsite equipment level (e.g., wellsite subsystems,etc.).

As an example, the Maestro block 902 may receiving information from adrilling workflow framework and/or one or more other sources, which maybe remote from a wellsite.

In the example of FIG. 9, the Maestro block 902 includes a plan/replanblock 922, an orchestrate/arbitrate block 924 and a local resourcemanagement block 926. In the example of FIG. 9, the Opera block 904includes an integrated execution block 944, which can include or beoperatively coupled to blocks for various subsystems of a wellsite suchas a drilling subsystem, a mud management subsystem (e.g., a hydraulicssubsystem), a casing subsystem (e.g., casings and/or completionssubsystem), and, for example, one or more other subsystems. In theexample of FIG. 9, the Core & Services block 906 includes a datamanagement and real-time services block 964 (e.g., real-time or nearreal-time services) and a rig and cloud security block 968 (see, e.g.,the system 500 of FIG. 5 as to provisioning and various type of securitymeasures, etc.). In the example of FIG. 9, the Equipment block 908 isshown as being capable of providing various types of information to theCore & Services block 906. For example, consider information from a rigsurface sensor, a LWD/MWD sensor, a mud logging sensor, a rig controlsystem, rig equipment, personnel, material, etc. In the example, of FIG.9, a block 970 can provide for one or more of data visualization,automatic alarms, automatic reporting, etc. As an example, the block 970may be operatively coupled to the Core & Services block 906 and/or oneor more other blocks.

As mentioned, a portion of the system 900 can be remote from a wellsite.For example, to one side of a dashed line appear a remote operationcommand center block 992, a database block 993, a drilling workflowframework block 994, a SAP/ERP block 995 and a field services deliveryblock 996. Various blocks that may be remote can be operatively coupledto one or more blocks that may be local to a wellsite system. Forexample, a communication link 912 is illustrated in the example of FIG.9 that can operatively couple the blocks 906 and 992 (e.g., as tomonitoring, remote control, etc.), while another communication link 914is illustrated in the example of FIG. 9 that can operatively couple theblocks 906 and 996 (e.g., as to equipment delivery, equipment services,etc.). Various other examples of possible communication links are alsoillustrated in the example of FIG. 9.

As an example, the system 900 of FIG. 9 may be a field management tool.As an example, the system 900 of FIG. 9 may include a drilling framework(see, e.g., the drilling frameworks 304 and 620). As an example, blocksin the system 900 of FIG. 9 that may be remote from a wellsite mayinclude various features of the services 790 of FIG. 7.

As an example, a wellbore can be drilled according to a drilling planthat is established prior to drilling. Such a drilling plan, which maybe a well plan or a portion thereof, can set forth equipment, pressures,trajectories and/or other parameters that define drilling process for awellsite. As an example, a drilling operation may then be performedaccording to the drilling plan (e.g., well plan). As an example, asinformation is gathered, a drilling operation may deviate from adrilling plan. Additionally, as drilling or other operations areperformed, subsurface conditions may change. Specifically, as newinformation is collected, sensors may transmit data to one or moresurface units. As an example, a surface unit may automatically use suchdata to update a drilling plan (e.g., locally and/or remotely).

As an example, the drilling workflow framework 994 can be or include aG&G system and a well planning system. As an example, a G&G systemcorresponds to hardware, software, firmware, or a combination thereofthat provides support for geology and geophysics. In other words, ageologist who understands the reservoir may decide where to drill thewell using the G&G system that creates a three-dimensional model of thesubsurface formation and includes simulation tools. The G&G system maytransfer a well trajectory and other information selected by thegeologist to a well planning system. The well planning systemcorresponds to hardware, software, firmware, or a combination thereofthat produces a well plan. In other words, the well plan may be ahigh-level drilling program for the well. The well planning system mayalso be referred to as a well plan generator.

In the example of FIG. 9, various blocks can be components that maycorrespond to one or more software modules, hardware infrastructure,firmware, equipment, or any combination thereof. Communication betweenthe components may be local or remote, direct or indirect, viaapplication programming interfaces, and procedure calls, or through oneor more communication channels.

As an example, various blocks in the system 900 of FIG. 9 can correspondto levels of granularity in controlling operations of associated withequipment and/or personnel in an oilfield. As shown in FIG. 9, thesystem 900 can include the Maestro block 902 (e.g., for well planexecution), the Opera block 904 (e.g., process manager collection), theCore & Services block 906, and the Equipment block 908.

The Maestro block 902 may be referred to as a well plan executionsystem. For example, a well plan execution system corresponds tohardware, software, firmware or a combination thereof that performs anoverall coordination of the well construction process, such ascoordination of a drilling rig and the management of the rig and the rigequipment. A well plan execution system may be configured to obtain thegeneral well plan from well planning system and transform the generalwell plan into a detailed well plan. The detailed well plan may includea specification of the activities involved in performing an action inthe general well plan, the days and/or times to perform the activities,the individual resources performing the activities, and otherinformation.

As an example, a well plan execution system may further includefunctionality to monitor an execution of a well plan to track progressand dynamically adjust the plan. Further, a well plan execution systemmay be configured to handle logistics and resources with respect to onand off the rig. As an example, a well plan execution system may includemultiple sub-components, such as a detailer that is configured to detailthe well planning system plan, a monitor that is configured to monitorthe execution of the plan, a plan manager that is configured to performdynamic plan management, and a logistics and resources manager tocontrol the logistics and resources of the well. In one or moreembodiments, a well plan execution system may be configured tocoordinate between the different processes managed by a process managercollection (see, e.g., the Opera block 904). In other words, a well planexecution system can communicate and manage resource sharing betweenprocesses in a process manager collection while operating at, forexample, a higher level of granularity than process manager collection.

As to the Opera block 904, as mentioned, it may be referred to as aprocess manager collection. In one or more embodiments, a processmanager collection can include functionality to perform individualprocess management of individual domains of an oilfield, such as a rig.For example, when drilling a well, different activities may beperformed. Each activity may be controlled by an individual processmanager in the process manager collection. A process manager collectionmay include multiple process managers, whereby each process managercontrols a different activity (e.g., activity related to the rig). Inother words, each process manager may have a set of tasks defined forthe process manager that is particular to the type of physics involvedin the activity. For example, drilling a well may use drilling mud,which is fluid pumped into well in order to extract drill cuttings fromthe well. A drilling mud process manager may exist in a process managercollection that manages the mixing of the drilling mud, the composition,testing of the drilling mud properties, determining whether the pressureis accurate, and performing other such tasks. The drilling mud processmanager may be separate from a process manager that controls movement ofdrill pipe from a well. Thus, a process manager collection may partitionactivities into several different domains and manages each of thedomains individually. Amongst other possible process managers, a processmanager collection may include, for example, a drilling process manager,a mud preparation and management process manager, a casing runningprocess manager, a cementing process manager, a rig equipment processmanager, and other process managers. Further, a process managercollection may provide direct control or advice regarding the componentsabove. As an example, coordination between process managers in a processmanager collection may be performed by a well plan execution system.

As to the Core & Service block 906 (e.g., a core services block or CSblock), it can include functionality to manage individual pieces ofequipment and/or equipment subsystems. As an example, a CS block caninclude functionality to handle basic data structure of the oilfield,such as the rig, acquire metric data, produce reports, and managesresources of people and supplies. As an example, a CS block may includea data acquirer and aggregator, a rig state identifier, a real-time (RT)drill services (e.g., near real-time), a reporter, a cloud, and aninventory manager.

As an example, a data acquirer and aggregator can include functionalityto interface with individual equipment components and sensor and acquiredata. As an example, a data acquirer and aggregator may further includefunctionality to interface with sensors located at the oilfield.

As an example, a rig state identifier can includes functionality toobtain data from the data acquirer and aggregator and transform the datainto state information. As an example, state information may includehealth and operability of a rig as well as information about aparticular task being performed by equipment.

As an example, RT drill services can include functionality to transmitand present information to individuals. In particular, the RT drillservices can include functionality to transmit information toindividuals involved according to roles and, for example, device typesof each individual (e.g., mobile, desktop, etc.). In one or moreembodiments, information presented by RT drill services can be contextspecific, and may include a dynamic display of information so that ahuman user may view details about items of interest.

As an example, in one or more embodiments, a reporter can includefunctionality to generate reports. For example, reporting may be basedon requests and/or automatic generation and may provide informationabout state of equipment and/or people.

As an example, a wellsite “cloud” framework can correspond to aninformation technology infrastructure locally at an oilfield, such as anindividual rig in the oilfield. In such an example, the wellsite “cloud”framework may be an “Internet of Things” (IoT) framework. As an example,a wellsite “cloud” framework can be an edge of the cloud (e.g., anetwork of networks) or of a private network.

As an example, an inventory manager can be a block that includesfunctionality to manage materials, such as a list and amount of eachresource on a rig.

In the example of FIG. 9, the Equipment block 908 can correspond tovarious controllers, control unit, control equipment, etc. that may beoperatively coupled to and/or embedded into physical equipment at awellsite such as, for example, rig equipment. For example, the Equipmentblock 908 may correspond to software and control systems for individualitems on the rig. As an example, the Equipment block 908 may provide formonitoring sensors from multiple subsystems of a drilling rig andprovide control commands to multiple subsystem of the drilling rig, suchthat sensor data from multiple subsystems may be used to provide controlcommands to the different subsystems of the drilling rig and/or otherdevices, etc. For example, a system may collect temporally and depthaligned surface data and downhole data from a drilling rig and transmitthe collected data to data acquirers and aggregators in core services,which can store the collected data for access onsite at a drilling rigor offsite via a computing resource environment.

In one or more embodiments, a method can include performing dynamicscheduling of a plan, which can include rescheduling of a plan. In suchan example, a plan may be revised at least in part. As an example, aplan can be a well plan or, for example, a portion of a well plan. As anexample, various components at various levels of granularity may beconfigured to continually monitor performance of tasks at acorresponding level of granularity of a component and, for example,update the plan based on state information about the performance oftasks.

As used in the following discussion, components in different levels ofgranularity may each have an individual plan that is based on the levelof granularity. For example, a well plan execution system plan can be anoverall plan for a well or entire oilfield while a process managercollection process manages performance of domain plans that can bespecific to a respective process of a manager's domain. As an example, awell plan execution system may monitor and schedule tasks at a levelthat differs from that of an individual process manager level. Forexample, a well plan execution system may controls the execution ofactivities by process managers. As an example, a well plan executionsystem may enable interrelationships between process managers such that,for example, control information due to a delay of one process manageris transmitted to another process manager.

As an example, a plan can be a set of events or activities to be carriedout to change the state of a well or a component thereof from a firststate to a second state (e.g., a desired state) for the well orcomponent thereof. In such an example, a plan may define, for one ormore events: a list of any tasks in the plan that are to precede thetask, an action to which the task relates, and a condition for the task.The condition may be, for example, an authorizing precondition detailingcriterion that should happen before the task may be performed, aconfirming condition defining when performance of the task is complete,and a failure condition defining when the performance of the task may bein error. For example, the failure condition may be the value of statesof oilfield equipment that is indicative of a failure to comply with theplan and a call for rescheduling.

Performing tasks according to the plan may include, based upon adetermination that one or more defined predecessor tasks for one or moretasks have been completed, and further starting at least one task of theplan, independently of time, based upon a determination that apre-authorizing condition has been met. Performance of a task may becontinually monitored to check for a failure condition being satisfied,and to check whether any confirming condition is satisfied. In someembodiments, the plan is scheduled according to time. In otherembodiments, management of the plan is time independent.

As an example, one or more obstacles may occur in implementation of aplan. Thus, for example, in one or more embodiments, a method maycontinuously reassess state(s) of a system; regenerate a plan thatregenerates a sequence of tasks in a second way (e.g., an optimal way).In one or more embodiments, regeneration can be performed continuallytaking into account a current state of an oilfield and a second state ofthe oilfield (e.g., desired state of the oilfield). In some embodiments,regeneration of a plan is performed when a failure condition isdetermined to exist.

In some embodiments, each portion of a system can be continuously and/orcontinually reassessed as to its state and a method can includegenerating a plan based on current state(s) to achieve a desired statefor one or more portions of the system. In other words, the processmanagers of process manager collection, when executing a plan, maycontinually obtain state information from equipment (e.g., one or moresubsystems through the core services) to identify one or more relevantstates of the system. If the state information indicates a delay orfailure condition, then the corresponding process managers of processmanager collection may re-plan to achieve the desired state. Forexample, the process manager may automatically regenerate the sequenceof tasks within the domain or level of granularity of the processmanager.

If the re-planning is not possible in a process manager's domain, thenre-planning may be elevated to a next level of granularity. For example,the re-planning from a particular process manager's domain may beelevated to the well plan execution system domain (e.g., passed from onelevel to another level).

As an example, a well planning system may have engineering expertise tomake design choices for an overall plan. In such a scenario, a well planexecution system may regenerate a plan optionally without involving thewell planning system, for example, as long as the new plan does notsubstantially alter engineering of the well. In particular, a well planexecution system might track resources that are being used by each of aplurality of process managers, but might not, for example, track one ormore individual tasks of each of the plurality of process managers.Thus, when a process manager is re-planning, a well plan executionsystem might track which resources are available before, during, and/orafter re-planning without having data regarding the details of the plan.In some embodiments the same re-planning may be used for multipleprocess managers and, in in some cases, a well plan execution system. Inother embodiments, at least some components of the system may use adifferent re-planning engine.

In one or more embodiments, dependency information is maintained atvarious levels of granularity and managed at the various levels ofgranularity. Thus, if a component performs planning (e.g., re-planning,etc.) that cause a delay in a dependent task, the component mayinstitute a change in the dependent task. If the change is with respectto a different domain, then the component may notify the process managerdirectly, or notify well plan execution system of the change.

FIG. 10 shows an example of a method 1000 that includes a commencementblock 1010 for commencing a workflow that includes operation ofequipment; a generation block 1020 for generating, for a well and alevel of detail of a component, a well plan that includes tasks; adeployment block 1030 for deploying tasks to oilfield equipment (e.g.,for deploying to systems and/or devices that can include mobile devicesassociated with individuals, etc.); a monitor block 1040 for monitoringperformance of one or more tasks to obtain state information (e.g., asto one or more states); a dynamic schedule block 1050 for dynamicallyscheduling and deploying one or more tasks according to at least aportion of the state information (e.g., consider a state-based machinethat is triggered by information related to states and/or statetransitions, etc.); a decision block 1060 for deciding whether one ormore tasks are complete (e.g., achieved a desired state or states); anda termination block 1070 for terminating the method 1000, for example,where tasks and desired states have been achieved as to the well plan,which can include completion of the well according to the well plan,which may be a revised well plan depending on one or more circumstancesthat may arise during performance of various operations (e.g., tasks,etc.).

As shown in the example of FIG. 10, where the decision block 1060decides to follow the “No” branch, the method 1000 can continue to, forexample, the monitor block 1040 for monitoring performance; whereas,where the decision block 1060 decides to follow the “Yes” branch, themethod 1000 can continue to, for example, the termination block 1070. Asan example, the method 1000 can include a plurality of blocks that formloops that may operate based on tasks being performed. As an example,some tasks may be sequential and/or in parallel. As an example, themethod 1000 can include a plurality of decision blocks for individualtasks and, for example, a data structure that can track tasks (e.g., asto the status of a task or tasks).

As an example, various blocks in FIG. 10 may be executed in differentorders, may be combined or omitted, and at least some of the blocks maybe executed in parallel. Furthermore, the blocks may be performedactively or passively. For example, some blocks may be performed usingpolling or be interrupt-driven in accordance with one or moreembodiments. By way of an example, some blocks (e.g., decision blocks,logic blocks, etc.) might not require a processor to process aninstruction unless an interrupt is received to signify that conditionexists in accordance with one or more embodiments. As another example,one or more blocks may be performed by performing a test, such aschecking a data value to test whether the value is consistent with thetested condition in accordance with one or more embodiments.

As an example, the method 1000 of FIG. 10 may be implemented at least inpart via at least a portion of the system 900 of FIG. 9. As an example,the method 1000 may be implemented by the system 900 of FIG. 9.

As an example, in the generation block 1020, for a well and the level ofgranularity of a component of a system, a well plan can be generatedthat includes multiple tasks. As an example, in the deployment block1030, tasks can be deployed to oilfield equipment according to the wellplan. As an example, in the monitor block 1040, performance of tasks canmonitored, for example, to obtain state information. As an example, inthe dynamical schedule block 1050, one or more tasks can be dynamicallyscheduled (e.g., scheduled for a first time, rescheduled, etc.) anddeployed where such scheduling can be based at least in part on stateinformation. As an example, in the decision block 1060, a decision(e.g., determination, etc.) can be made as to whether a desired state(e.g., target state, etc.) has been achieved; if not, the method 1000can proceed, for example, to the monitor block 1040 and, if achieved,the method 1000 may terminate (e.g., depending on particular portion ofa well plan, an entire well plan, etc. that is being addressed by themethod 1000).

FIG. 11 shows an example of a graphical user interface (GUI) 1100 thatincludes various subsystem tasks as may be part of a well plan. Forexample, a rig up subsystem, a casing subsystem, a cement subsystem, adrilling subsystem and a rig down subsystem are illustrated as somepossible examples of subsystems that can include associated tasks. Asshown in the example of FIG. 11, the GUI 1100 includes a timeline, whichcan be incremented by minute, hour, day, etc. In the example of FIG. 11,the GUI 1100 can be render information as to scheduled tasks that areorganized by subsystem type where a scheduled task may aim to achieve adesired state of wellsite equipment.

In the example of FIG. 11, the various scheduled tasks are shown asSub-Activities and as other types of tasks (e.g., Idle, Bit Run, etc.),which may be considered to be Sub-Activities. As an example, graphicalcontrols can allow for addition of one or more new activities (e.g.,scheduling of new tasks). As an example, graphical controls can allowfor rescheduling one or more tasks.

In the example of FIG. 11, a dashed box represents a display device ontowhich the GUI 1100 can be rendered. For example, consider a flat paneldisplay, which may be, for example, a touchscreen display.

FIG. 12 shows an example of a GUI 1200 that is rendered to a displaydevice 1201, represented by a dashed box. For example, consider a flatpanel display, which may be, for example, a touchscreen display.

In the example of FIG. 12, the GUI 1200 may be an operational dashboardwhere the state of one or more pieces of equipment, operations, etc. maybe rendered visually, for example, via graphics and/or numbers. As anexample, various colors may be utilized to convey state information. Asan example, audio may be associated with the GUI 1200 and changesthereto, etc. For example, where a parameter reaches a limit, a colorchange may occur to a graphic of the display device 1201 and an audioalarm may be rendered via one or more speakers.

FIG. 13 shows an example of a GUI 1300 rendered to a display device 1301and an example of a GUI 1350 rendered to a display device 1303. As anexample, a display device can be a mobile device (e.g., a smart phone, atablet, a notebook computer, etc.).

As an example, the GUI 1300 may be rendered to a mobile deviceassociated with a role of an individual at a wellsite. As an example,task information may be rendered to the GUI 1300, optionally with acorresponding status. As an example, a GUI 1300 may present a flag thatcan be actuated to alert an individual via a device that a change is tobe made, has been made and/or has been made in a manner that informationhas changed. As to the latter, a change may be associated with asensitivity. For example, where an individual adjusts a valve orinstructs a controller to adjust a valve, the information rendered tothe GUI 1300 may change in response to the adjustment to the valve,which can cause a device to render a visual and/or an audible alert. Forexample, upon adjustment of a valve, a wellsite system may receiveinformation via one or more sensors and then transmit information to amobile device for rendering to a display of the mobile device. Wheresuch information indicates that a change, which may be an expectedchange, has occurred (e.g., a change in state), the mobile device maylocally determine (e.g., via execution of instructions locally) that theadjustment implemented (e.g., according to a scheduled task) has beensuccessful in transitioning one or more subsystems to a desired state orstates. In such a manner, the individual using the mobile device has alevel of control over what information (e.g., alerts) are rendered viathe mobile device (e.g., visually and/or audibly). As an example, awellsite system may provide a different mechanism for an individualusing, for example, a desktop computer with a large flat panel display(e.g., in a driller cabin, etc.).

As an example, where a desired state is not achieved, informationreceived by a wellsite system can perform one or more actions that mayinclude scheduling one or more tasks, which can include rescheduling thetask that may have been unsuccessful or, for example, not performed dueto an unavailability of an individual (e.g., to adjust a valve, etc.)and/or due to an unavailability of a component (e.g., to electronicallycontrol a valve, etc.). As an example, a wellsite system can determine astatus of a task and schedule one or more tasks based at least in parton the status.

In the example of FIG. 13, the GUI 1350 may allow for input from thefield, for example, to configure one or more parameters associated withthe GUI 1300. In such an example, a user of a mobile device may have alevel of authority to enter such parameters, which may be, in turn,transmitted to a wellsite system (see, e.g., the GUI 1200 of FIG. 12).

FIG. 14 shows an example of a GUI 1400 rendered to a display device 1401and an example of a GUI 1450 rendered to a display device 1403. As anexample, a display device can be a mobile device (e.g., a smart phone, atablet, a notebook computer, etc.). As an example, the GUIs 1400 and1450 may be operative in one or more manners such as the GUIs 1300 and1350 of FIG. 13.

As an example, one or more GUIs may provide menu options for settingcommunications such as instant messaging. For example, a wellsite systemcan include an instant messaging server that can handle communicationswith respect to client devices. As shown in the example GUIs 1350 and1450, graphical icons that are graphical controls can allow for settingaudible messages and instant messages for information, which may be, forexample, state information (e.g., associated with a state of asubsystem, etc.).

FIG. 15 shows an example of a GUI 1500 rendered to a display device1501, which may be, for example, a smart phone, a tablet, etc. As shown,the GUI 1500 can include a plurality of individual GUIs such as, forexample, the GUI 1300 of FIG. 13, the GUI 1400 of FIG. 14, etc. In theexample of FIG. 15, the GUI includes “dials” (e.g., arcuate and/orlinear) and tracks with respect to time (e.g., bars, plots, etc.). As anexample, the display device 1501 can be a touchscreen display devicesuch that a user may utilize touch (e.g., finger, multi-finger,gestures, etc.) to navigate and/or command the GUI 1500.

FIG. 16 shows an example of a method 1600 that includes a parse block1610 for parsing scheduled tasks for a mud task; a reception block 1620for receiving the mud task at a mud engineer device; a render block 1630for rendering mud task information to a display of the mud engineerdevice; a reception block 1640 for receiving information associated withthe mud task; and a confirmation block 1650 for confirming status of themud task.

As an example, the parse block 1610 can include parsing scheduled tasksto generate a GUI such as a GUI akin to the GUI 1200 of FIG. 12, whichshows various tasks according to a timeline where such tasks can beorganized, for example, according to subsystems. Such parsing may beperformed, for example, by a wellsite system (e.g., wellsite computingsystem such as, for example, the computing system 770 of FIG. 7). As anexample, the reception block 1620 may be performed by a mobile devicesuch as, for example, the mobile device 1501 of FIG. 15. As an example,the render block 1630 may be performed by the mobile device, forexample, to render a GUI such as the GUI 1300 of FIG. 13.

In the example of FIG. 16, the reception block 1640 may be performed byone or more devices and/or systems. For example, a user may interactwith a GUI rendered to a mobile device such that at least the mobiledevice receives information and/or equipment at a wellsite may transmitinformation to a wellsite computing system such that the wellsitecomputing system receives information, which may then be transmitted toand received by the mobile device. In the example of FIG. 16, theconfirmation block 1650 may be performed akin to the reception block1640, for example, by a mobile device associated with a role and a taskand/or by a wellsite computing system that can receive information suchas sensed information via one or more sensors, transmitted informationvia one or more GUIs, microphones, etc. of a mobile device, etc.

As an example, the method 1600 can be associated with the method 1000.For example, the method 1600 may be an example implementation as to aportion of the method 1000. As an example, where the confirmation block1650 of the method 1600 is not successful (e.g., after a period of time,etc.), the method 1600 may include receiving another mud task via thereception block 1620. In such an example, the method 1600 can includeone or more loops.

As an example, the method 1600 may be implemented at least in part via amobile device that can be carried by an individual that has an assignedrole. In such an example, the mobile device can have an address and/oran identifier that can be utilized by a wellsite computing system forpurposes of communications and/or locating the individual, whether onand/or off the wellsite. As to locating an individual via location of adevice, such information may be state information as to the state of theindividual with respect to one or more tasks.

FIG. 17 shows an example of a method 1700 that includes a parse block1710 for parsing scheduled tasks for an equipment maintenance task; areception block 1720 for receiving the equipment maintenance task at anequipment maintenance engineer device; a render block 1730 for renderingequipment maintenance task information to a display of the equipmentmaintenance engineer device; a reception block 1740 for receivinginformation associated with the equipment maintenance task; and aconfirmation block 1750 for confirming status of the equipmentmaintenance task.

In the example of FIG. 17, the parsing of the scheduled tasks may beperformed via a wellsite computing system, for example, responsive tothe state of a piece of wellsite equipment. For example, where machineryis to be lubricated, lack of lubrication may place the machinery at riskof damage, failure, etc. In such an example, there may be someuncertainty as to when lubrication is to be performed (e.g., a scheduledmaintenance task may be at a time, order, etc. that is estimated). As anexample, a lubrication task may be automated in response to informationreceived via one or more sensors that indicate that a piece of machinerycan benefit from lubrication. In such an example, an associated task maybe automatically scheduled (e.g., automatically appear in a GUI such asthe GUI 1100 of FIG. 11). In such an example, a background process maybe executed by the wellsite computing system (e.g., a drillingframework, etc.) that can catch automatically scheduled tasks that mayappear from time to time such that they are handled properly (e.g.,transmitted to one or more individuals, etc., via appropriate devices,etc.).

FIG. 18 shows an example of a method 1800 that includes a receptionblock 1810 for receiving scheduled tasks associated with subsystems of awellsite system where the scheduled tasks are associated withachievement of desired states of the wellsite system; a transmissionblock 1820 for transmitting task information for at least a portion ofthe scheduled tasks to computing devices associated with the subsystems;a reception block 1830 for receiving state information via the wellsitesystem; an assessment block 1840 for assessing the state informationwith respect to one or more of the desired states; a scheduling block1850 for, based at least in part on the assessing, scheduling a task;and a transmission block 1860 for transmitting task information for thetask to one or more of the computing devices associated with thesubsystems.

The method 1800 is shown in FIG. 18 in association with variouscomputer-readable media (CRM) blocks 1811, 1821, 1831, 1841, 1851 and1861. Such blocks generally include instructions suitable for executionby one or more processors (or cores) to instruct a computing device orsystem to perform one or more actions. While various blocks are shown, asingle medium may be configured with instructions to allow for, at leastin part, performance of various actions of the method 1800. As anexample, a computer-readable medium (CRM) may be a computer-readablestorage medium that is non-transitory and not a carrier wave. As anexample, the blocks 1811, 1821, 1831, 1841, 1851 and 1861 may beprovided as one or more modules, for example, such as the one or moremodules and/or instructions 1902 of the system 1900 of FIG. 19. As anexample, the method 1800 of FIG. 18 may include rendering information toa display or to display (e.g., via transmission, via direct rendering bya device performing a portion of the method, etc.).

As an example, a method can include receiving scheduled tasks associatedwith subsystems of a wellsite system where the scheduled tasks areassociated with achievement of desired states of the wellsite system;transmitting task information for at least a portion of the scheduledtasks to computing devices associated with the subsystems; receivingstate information via the wellsite system; assessing the stateinformation with respect to one or more of the desired states; based atleast in part on the assessing, scheduling a task; and transmitting taskinformation for the task to one or more of the computing devicesassociated with the subsystems. In such an example, the method caninclude assessing via determining whether the wellsite system achievedone of the desired states based at least in part on transmitted taskinformation for one of the scheduled tasks. In such an example, thescheduling a task can include rescheduling the one of the scheduledtasks where the wellsite system did not achieve the one of the desiredstates and/or the scheduling a task can include scheduling a new taskwhere the wellsite system did not achieve the one of the desired states.

As an example, scheduling a task can include scheduling a new task basedat least in part on assessing (e.g., one or more assessments).

As an example, a method can include repeating of receiving of stateinformation after, for example, transmitting task information for atask.

As an example, task information can include task information for a mudsubsystem. As an example, task information can include task informationfor maintenance of a piece of equipment of a subsystem (e.g., of aplurality of subsystems of a wellsite system, etc.).

As an example, state information can include sensed information acquiredby one or more sensors of a wellsite system.

As an example, state information can include user input informationinput via a graphical user interface rendered to a display operativelycoupled to one of a plurality of computing devices.

As an example, scheduling a task can include interacting with agraphical user interface rendered to a display operatively coupled to awellsite computing system. In such an example, the graphical userinterface can include a timeline and subsystem information. As anexample, a graphical user interface can include at least one taskcreation control graphic. As an example, a graphical user interface caninclude a plurality of task creation control graphics where each ofplurality of task control graphics is specialized for a correspondingone of a plurality of subsystems (e.g., of a wellsite system).

As an example, a system can include one or more processors; memoryoperatively coupled to the one or more processors; andprocessor-executable instructions stored in the memory and executable byat least one of the processors to instruct the system to receivescheduled tasks associated with subsystems of a wellsite system wherethe scheduled tasks are associated with achievement of desired states ofthe wellsite system; transmit task information for at least a portion ofthe scheduled tasks to computing devices associated with the subsystems;receive state information via the wellsite system; assess the stateinformation with respect to one or more of the desired states to provideone or more assessments; based at least in part on at least one of theone or more assessments, schedule a task; and transmit task informationfor the task to one or more of the computing devices associated with thesubsystems. In such an example, the system can include instructions toinstruct the system to assess the state information dynamicallyresponsive to receipt of the state information.

As an example, a system can include instructions to instruct the systemto schedule a task dynamically responsive to one or more of one or moreassessments.

As an example, a system can include a display operatively coupled to oneor more processors where instructions to schedule a task includeinstructions to receive input via a graphical user interface rendered tothe display.

As an example, one or more computer-readable storage media can includecomputer-executable instructions executable to instruct a computingsystem to: receive scheduled tasks associated with subsystems of awellsite system where the scheduled tasks are associated withachievement of desired states of the wellsite system; transmit taskinformation for at least a portion of the scheduled tasks to computingdevices associated with the subsystems; receive state information viathe wellsite system; assess the state information with respect to one ormore of the desired states to provide one or more assessments; based atleast in part on at least one of the one or more assessments, schedule atask; and transmit task information for the task to one or more of thecomputing devices associated with the subsystems. In such an example,instructions can be included to instruct a computing system to receiveinput via a graphical user interface rendered to a display.

According to an embodiment, one or more computer-readable media mayinclude computer-executable instructions to instruct a computing systemto output information for controlling a process. For example, suchinstructions may provide for output to sensing process, an injectionprocess, drilling process, an extraction process, an extrusion process,a pumping process, a heating process, etc.

In some embodiments, a method or methods may be executed by a computingsystem. FIG. 19 shows an example of a system 1900 that can include oneor more computing systems 1901-1, 1901-2, 1901-3 and 1901-4, which maybe operatively coupled via one or more networks 1909, which may includewired and/or wireless networks.

As an example, a system can include an individual computer system or anarrangement of distributed computer systems. In the example of FIG. 19,the computer system 1901-1 can include one or more modules 1902, whichmay be or include processor-executable instructions, for example,executable to perform various tasks (e.g., receiving information,requesting information, processing information, simulation, outputtinginformation, etc.).

As an example, a module may be executed independently, or incoordination with, one or more processors 1904, which is (or are)operatively coupled to one or more storage media 1906 (e.g., via wire,wirelessly, etc.). As an example, one or more of the one or moreprocessors 1904 can be operatively coupled to at least one of one ormore network interface 1907. In such an example, the computer system1901-1 can transmit and/or receive information, for example, via the oneor more networks 1909 (e.g., consider one or more of the Internet, aprivate network, a cellular network, a satellite network, etc.).

As an example, the computer system 1901-1 may receive from and/ortransmit information to one or more other devices, which may be orinclude, for example, one or more of the computer systems 1901-2, etc. Adevice may be located in a physical location that differs from that ofthe computer system 1901-1. As an example, a location may be, forexample, a processing facility location, a data center location (e.g.,server farm, etc.), a rig location, a wellsite location, a downholelocation, etc.

As an example, a processor may be or include a microprocessor,microcontroller, processor module or subsystem, programmable integratedcircuit, programmable gate array, or another control or computingdevice.

As an example, the storage media 1906 may be implemented as one or morecomputer-readable or machine-readable storage media. As an example,storage may be distributed within and/or across multiple internal and/orexternal enclosures of a computing system and/or additional computingsystems.

As an example, a storage medium or storage media may include one or moredifferent forms of memory including semiconductor memory devices such asdynamic or static random access memories (DRAMs or SRAMs), erasable andprogrammable read-only memories (EPROMs), electrically erasable andprogrammable read-only memories (EEPROMs) and flash memories, magneticdisks such as fixed, floppy and removable disks, other magnetic mediaincluding tape, optical media such as compact disks (CDs) or digitalvideo disks (DVDs), BLUERAY® disks, or other types of optical storage,or other types of storage devices.

As an example, a storage medium or media may be located in a machinerunning machine-readable instructions, or located at a remote site fromwhich machine-readable instructions may be downloaded over a network forexecution.

As an example, various components of a system such as, for example, acomputer system, may be implemented in hardware, software, or acombination of both hardware and software (e.g., including firmware),including one or more signal processing and/or application specificintegrated circuits.

As an example, a system may include a processing apparatus that may beor include a general purpose processors or application specific chips(e.g., or chipsets), such as ASICs, FPGAs, PLDs, or other appropriatedevices.

FIG. 20 shows components of a computing system 2000 and a networkedsystem 2010. The system 2000 includes one or more processors 2002,memory and/or storage components 2004, one or more input and/or outputdevices 2006 and a bus 2008. According to an embodiment, instructionsmay be stored in one or more computer-readable media (e.g.,memory/storage components 2004). Such instructions may be read by one ormore processors (e.g., the processor(s) 2002) via a communication bus(e.g., the bus 2008), which may be wired or wireless. The one or moreprocessors may execute such instructions to implement (wholly or inpart) one or more attributes (e.g., as part of a method). A user mayview output from and interact with a process via an I/O device (e.g.,the device 2006). According to an embodiment, a computer-readable mediummay be a storage component such as a physical memory storage device, forexample, a chip, a chip on a package, a memory card, etc.

According to an embodiment, components may be distributed, such as inthe network system 2010. The network system 2010 includes components2022-1, 2022-2, 2022-3, . . . 2022-N. For example, the components 2022-1may include the processor(s) 2002 while the component(s) 2022-3 mayinclude memory accessible by the processor(s) 2002. Further, thecomponent(s) 2022-2 may include an I/O device for display and optionallyinteraction with a method. The network may be or include the Internet,an intranet, a cellular network, a satellite network, etc.

As an example, a device may be a mobile device that includes one or morenetwork interfaces for communication of information. For example, amobile device may include a wireless network interface (e.g., operablevia IEEE 802.11, ETSI GSM, BLUETOOTH®, satellite, etc.). As an example,a mobile device may include components such as a main processor, memory,a display, display graphics circuitry (e.g., optionally including touchand gesture circuitry), a SIM slot, audio/video circuitry, motionprocessing circuitry (e.g., accelerometer, gyroscope), wireless LANcircuitry, smart card circuitry, transmitter circuitry, GPS circuitry,and a battery. As an example, a mobile device may be configured as acell phone, a tablet, etc. As an example, a method may be implemented(e.g., wholly or in part) using a mobile device. As an example, a systemmay include one or more mobile devices.

As an example, a system may be a distributed environment, for example, aso-called “cloud” environment where various devices, components, etc.interact for purposes of data storage, communications, computing, etc.As an example, a device or a system may include one or more componentsfor communication of information via one or more of the Internet (e.g.,where communication occurs via one or more Internet protocols), acellular network, a satellite network, etc. As an example, a method maybe implemented in a distributed environment (e.g., wholly or in part asa cloud-based service).

As an example, information may be input from a display (e.g., consider atouchscreen), output to a display or both. As an example, informationmay be output to a projector, a laser device, a printer, etc. such thatthe information may be viewed. As an example, information may be outputstereographically or holographically. As to a printer, consider a 2D ora 3D printer. As an example, a 3D printer may include one or moresubstances that can be output to construct a 3D object. For example,data may be provided to a 3D printer to construct a 3D representation ofa subterranean formation. As an example, layers may be constructed in 3D(e.g., horizons, etc.), geobodies constructed in 3D, etc. As an example,holes, fractures, etc., may be constructed in 3D (e.g., as positivestructures, as negative structures, etc.).

Although only a few examples have been described in detail above, thoseskilled in the art will readily appreciate that many modifications arepossible in the examples. Accordingly, all such modifications areintended to be included within the scope of this disclosure as definedin the following claims. In the claims, means-plus-function clauses areintended to cover the structures described herein as performing therecited function and not only structural equivalents, but alsoequivalent structures. Thus, although a nail and a screw may not bestructural equivalents in that a nail employs a cylindrical surface tosecure wooden parts together, whereas a screw employs a helical surface,in the environment of fastening wooden parts, a nail and a screw may beequivalent structures. It is the express intention of the applicant notto invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of theclaims herein, except for those in which the claim expressly uses thewords “means for” together with an associated function.

What is claimed is:
 1. A method comprising: receiving scheduled tasksassociated with subsystems of a wellsite system wherein the scheduledtasks are associated with achievement of desired states of the wellsitesystem; transmitting task information for at least a portion of thescheduled tasks to computing devices associated with the subsystems;receiving state information via the wellsite system; assessing the stateinformation with respect to one or more of the desired states; based atleast in part on the assessing, scheduling a task; and transmitting taskinformation for the task to one or more of the computing devicesassociated with the subsystems.
 2. The method of claim 1 wherein theassessing comprises determining whether the wellsite system achieved oneof the desired states based at least in part on transmitted taskinformation for one of the scheduled tasks.
 3. The method of claim 2wherein the scheduling a task comprises rescheduling the one of thescheduled tasks where the wellsite system did not achieve the one of thedesired states.
 4. The method of claim 2 wherein the scheduling a taskcomprises scheduling a new task where the wellsite system did notachieve the one of the desired states.
 5. The method of claim 1 whereinthe scheduling a task comprises scheduling a new task based at least inpart on the assessing.
 6. The method of claim 1 comprising repeating thereceiving of state information after the transmitting task informationfor the task.
 7. The method of claim 1 wherein the task informationcomprises task information for a mud subsystem.
 8. The method of claim 1wherein the task information comprises task information for maintenanceof a piece of equipment of one of the subsystems.
 9. The method of claim1 wherein the state information comprises sensed information acquired byone or more sensors of the wellsite system.
 10. The method of claim 1wherein the state information comprises user input information input viaa graphical user interface rendered to a display operatively coupled toone of the computing devices.
 11. The method of claim 1 wherein thescheduling a task comprising interacting with a graphical user interfacerendered to a display operatively coupled to a wellsite computingsystem.
 12. The method of claim 11 wherein the graphical user interfacecomprises a timeline and subsystem information.
 13. The method of claim11 wherein the graphical user interface comprises at least one taskcreation control graphic.
 14. The method of claim 11 wherein thegraphical user interface comprises a plurality of task creation controlgraphics wherein each of plurality of task control graphics isspecialized for a corresponding one of the subsystems.
 15. A systemcomprising: one or more processors; memory operatively coupled to theone or more processors; and processor-executable instructions stored inthe memory and executable by at least one of the processors to instructthe system to receive scheduled tasks associated with subsystems of awellsite system wherein the scheduled tasks are associated withachievement of desired states of the wellsite system; transmit taskinformation for at least a portion of the scheduled tasks to computingdevices associated with the subsystems; receive state information viathe wellsite system; assess the state information with respect to one ormore of the desired states to provide one or more assessments; based atleast in part on at least one of the one or more assessments, schedule atask; and transmit task information for the task to one or more of thecomputing devices associated with the subsystems.
 16. The system ofclaim 15 wherein the instructions to instruct the system to assess,assess the state information dynamically responsive to receipt of thestate information.
 17. The system of claim 15 wherein the instructionsto instruct the system to schedule, schedule the task dynamicallyresponsive to one or more of the one or more assessments.
 18. The systemof claim 15 comprising a display operatively coupled to the one or moreprocessors wherein the instructions to schedule a task comprisesinstructions to receive input via a graphical user interface rendered tothe display.
 19. One or more computer-readable storage media comprisingcomputer-executable instructions executable to instruct a computingsystem to: receive scheduled tasks associated with subsystems of awellsite system wherein the scheduled tasks are associated withachievement of desired states of the wellsite system; transmit taskinformation for at least a portion of the scheduled tasks to computingdevices associated with the subsystems; receive state information viathe wellsite system; assess the state information with respect to one ormore of the desired states to provide one or more assessments; based atleast in part on at least one of the one or more assessments, schedule atask; and transmit task information for the task to one or more of thecomputing devices associated with the subsystems.
 20. The one or morecomputer-readable storage media of claim 19 comprisingcomputer-executable instructions executable to instruct a computingsystem to receive input via a graphical user interface rendered to adisplay.